STAPPA

State and Territorial Air Pollution 

Program Administrators

ALAPCO

Association of Local Air 

Pollution Control Officials

March 2006

Controlling 

Fine Particulate Matter 

Under the Clean Air Act: 

A Menu of Options
STAPPA

State and Territorial Air Pollution 

Program Administrators

ALAPCO

Association of Local Air 

Pollution Control Offi cials

March 2006

Controlling 

Fine Particulate Matter 

Under the Clean Air Act: 

A Menu of Options
 Acknowledgements i

Acknowledgements 

On behalf of the State and Territorial Air Pollution 

Program Administrators (STAPPA) and the Association 

of Local Air Pollution Control Offi cials (ALAPCO), 

we are pleased to provide Controlling Fine Particulate 

Matter Under the Clean Air Act: A Menu of Options. Our 

associations developed this document to assist states and 

localities in determining the most effective ways to control 

emissions of fi ne particles (PM2.5) and PM2.5 precursors 

from sources in their areas. We hope that states and 

localities fi nd this document useful as they prepare 

their State Implementation Plans (SIPs) for attaining or 

maintaining the PM2.5 standard.

STAPPA and ALAPCO express gratitude to M.J Bradley 

& Associates, Inc. for its assistance in drafting this 

document, in particular, Ann Berwick, Michael Bradley, 

Tom Curry, Will Durbin, Dana Lowell and Chris Van 

Atten. We thank Brock Nicholson (North Carolina) and 

Lynne Liddington (Knox County, Tennessee), co-chairs 

of the associations’ Criteria Pollutants Committee, under 

whose guidance this document was prepared. We also 

appreciate the efforts of the STAPPA and ALAPCO PM2.5

Menu of Options Review Workgroup, who helped shape 

the options presented in this document. We thank Bill 

Becker, Executive Director of STAPPA and ALAPCO, and 

Amy Royden-Bloom, Senior Staff Associate of STAPPA 

and ALAPCO, who oversaw the project. Finally, we 

express our gratitude to EPA for providing the funding for 

this project.

Once again, we believe that Controlling Fine Particulate 

Matter Under the Clean Air Act: A Menu of Options

will serve as a useful and important resource for states 

and localities as they develop approaches to regulate 

emissions of PM2.5 and PM2.5 precursors and thank all who 

contributed to its development.

Eddie Terrill John Paul 

STAPPA President ALAPCO President
Contents iii

Contents

Introduction ........................................................................................................................................... 1

Chapter 1. The Highlights .................................................................................................................... 5

Chapter 2. Effects of Particulate Matter on Human Health and the Environment ....................... 16

Chapter 3. Fine Particulate Matter and Precursor Emissions ....................................................... 22

Chapter 4. The Clean Air Act ............................................................................................................. 32

Chapter 5. Boiler Technologies ........................................................................................................ 42

Chapter 6. Industrial and Commercial Boilers................................................................................. 60

Chapter 7. Electric Generating Units ................................................................................................ 86

Chapter 8. Pulp and Paper ............................................................................................................... 108

Chapter 9. Cement Manufacturing ................................................................................................. 120

Chapter 10. Iron and Steel ............................................................................................................... 136

Chapter 11. Petroleum Refi neries ................................................................................................... 158
iv Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Chapter 12. Diesel Engine Technologies ....................................................................................... 172

Chapter 13. Diesel Trucks and Buses............................................................................................. 188

Chapter 14. Nonroad Equipment ..................................................................................................... 202

Chapter 15. Light-Duty Cars and Trucks ........................................................................................ 216

Chapter 16. Airports ......................................................................................................................... 228

Chapter 17. Marine Ports ................................................................................................................. 238

Chapter 18. Residential Fuel Combustion and Electricity Use .................................................... 252

Chapter 19. Commercial Cooking ................................................................................................... 266

Chapter 20. Fugitive Dust ................................................................................................................ 274
 About STAPPA and ALAPCO v

The State and Territorial Air Pollution Program 

Administrators (STAPPA) and the Association of Local 

Air Pollution Control Offi cials (ALAPCO) are the two 

national associations of air quality offi cials in the states, 

territories and major metropolitan areas throughout the 

country. The members of STAPPA and ALAPCO have 

primary responsibility for implementing our nation’s air 

pollution control laws and regulations. The associations 

serve to encourage the exchange of information and 

experience among air pollution control offi cials; enhance 

communication and cooperation among federal, state 

About STAPPA and ALAPCO 

and local regulatory agencies; and facilitate air pollution 

control activities that will result in clean, healthful air 

across the country. STAPPA and ALAPCO share joint 

headquarters in Washington, DC. 

For further information, contact STAPPA and ALAPCO at 

444 North Capitol Street, NW, Suite 307, Washington, DC 

20001 (telephone: 202-624-7864; fax: 202-624-7863; email 

4cleanair@4cleanair.org) or visit our associations’ web site 

at www.4cleanair.org. 
 Introduction 1

The State and Territorial Air Pollution Program 

Administrators (STAPPA) and the Association of Local 

Air Pollution Control Offi cials (ALAPCO) have prepared 

Controlling Fine Particulate Matter Under the Clean Air 

Act: A Menu of Options (PM2.5 Menu of Options) to assist 

state and local air pollution control offi cials in evaluating 

the options for reducing fi ne particulate matter (PM2.5) and 

PM2.5-precursor emissions. 

Areas throughout the eastern U.S. and California (and one 

area in Montana) currently exceed EPA’s National Ambient 

Air Quality Standards (NAAQS) for PM2.5, and states must 

submit State Implementation Plans (SIPs) by April 2008 

detailing their plans for achieving the national standards. 

Meanwhile, the PM2.5 NAAQS are once again undergoing 

the periodic review that §109(d)(1) of the Clean Air Act 

requires take place at fi ve-year intervals. Under the terms 

of a consent decree, EPA is to issue fi nal standards by 

September 27, 2006. The Agency proposed new standards 

on January 17, 2006.

EPA estimates that meeting the current PM2.5 standards 

would avoid tens of thousands of premature deaths 

annually and save hundreds of thousands of people from 

signifi cant respiratory and cardiovascular disease. The 

Agency further estimates that the monetized health 

benefi ts of improvements in PM2.5 air quality exceed the 

costs by a substantial margin. 

PM2.5 is a complex pollutant with many sources 

Introduction

contributing to the ambient air quality problem. As a 

result, this PM2.5 Menu of Options addresses a broad 

array of emission source categories, ranging from 

household furnaces to petroleum refi neries. The challenge 

confronting air quality offi cials is tremendous, as 

evidenced by the sheer number of options that we identify 

for improving air quality. But therein lie the opportunities, 

as well.

Like STAPPA’s and ALAPCO’s previous document—

Controlling Particulate Matter Under the Clean Air 

Act: A Menu of Options—this document compiles and 

analyzes secondary information. It is intended to serve 

as a general reference for a national audience, and it will 

in no way substitute for a thorough analysis by state and 

local agencies of local emissions sources and conditions, 

using appropriate guidance from EPA and other available 

information.

What To Regulate

The national focus of this report should not obscure an 

absolutely central point: local choices about the sources 

and pollutants to control will need to be informed by 

highly local considerations. A particular source category 

may account for a small share of national PM2.5 emissions, 

but it may nonetheless dominate the local inventory.

The chemistry and physics of PM2.5 formation in the 

atmosphere is incompletely understood. Some PM2.5 is 
2 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

released directly to the atmosphere, and some forms from 

emissions of sulfur dioxide (SO2) and nitrogen oxides 

(NOx) (which are currently viewed as the most signifi cant 

precursors and are the only ones addressed in this report). 

Ammonia and volatile organic compounds (VOCs), 

which are not included in this report, can also contribute 

to ambient PM2.5. Direct PM2.5 emissions may be largely 

responsible for one area’s nonattainment, while SO2

emissions may cause the problem elsewhere. The choice of 

whether to focus on reducing direct PM2.5, SO2 or NOx—or 

all of them, or ammonia or VOCs—will depend on local 

source contributions and atmospheric chemistry.

There are further challenges for SIP writers. In a perfect 

world, control-effi ciency and cost-effectiveness data would 

be at hand; however, it is not consistently available. Of 

course, even when information of this sort can be found, it 

may not be applicable to all sources. 

And another source of uncertainty complicates the job. 

As we discuss in Chapter 3, Fine Particulate Matter and 

Precursor Emissions, there are important distinctions 

between fi lterable and condensable PM2.5. Further, some 

methods used to measure PM emissions refl ect only the 

fi lterable components and, to exacerbate the problem, the 

fi lterable components vary depending on the test method 

used. Although we discuss this issue in Chapter 3 in the 

context of the national PM2.5 inventory, the distinction 

between fi lterables and condensables also raises regulatory 

and permitting issues. 

The Authority to Regulate

Having decided what sources and pollutants need to 

be controlled in order to address PM2.5 nonattainment, 

regulators must then ascertain their authority to do so.

The Clean Air Act divides responsibility for various 

types of air pollution sources and air pollutants between 

the states and localities on the one hand and the federal 

government on the other. Generally, state and local 

regulators share responsibility with EPA for regulating 

so-called “criteria” pollutants from stationary and area 

sources (see Chapter 4, The Clean Air Act), with states and 

localities assigned the lead role in addressing emissions 

from these source categories. 

States and localities are free under federal law to adopt 

more stringent standards for stationary and area sources 

than the Clean Air Act requires. However, some states 

may be limited by state law or policy in whether they can 

enact requirements that are more stringent than federal 

standards. Here, we outline the possible approaches to 

tightening federal standards that states and localities may 

consider, and to developing standards where no federal 

programs exist.

For states that have no latitude or little latitude beyond 

what the Clean Air Act prescribes, the priority will be to 

ensure strict compliance with the limits that the Act and 

federal regulations impose on particulates and precursor 

pollutants. In these states, the precise language of the 

statutory limitation will inform the degree of regulatory 

latitude. For example, regulators in at least some of these 

states may not be able to set more stringent standards 

for those sources that federal law or regulations actually 

address, but in some of these states regulators may see 

their way clear to setting standards for smaller sources 

than those covered by federal requirements.

Moreover, there are no actual federal Reasonably Available 

Control Technology (RACT) standards—EPA issues 

only guidelines (and although the RACT standards are 

intended to refl ect real-time advancements in technology, 

many of the guidelines are seriously outdated). Since the 

guidelines do not set actual limits, even state prohibitions 

against enacting more stringent state standards may be 

inapplicable.

States and localities that are not limited to the requirements 

promulgated under federal law will want to look to the most 

stringent standards that regulators in other jurisdictions 

have imposed; we have identifi ed these throughout this 

Menu of Options. State and local authority to impose 

such limits derives from the federal requirement to attain 

the NAAQS. The options for imposing more stringent 

requirements than current federal regulations include the 

following:

Under the state or local version of federal regulatory 

air pollution programs, or through permit 

determinations, adopt the most stringent standards 

that appear to be feasible, even if they are more 

stringent than federal rules impose; or apply the 

federal or stricter standards to sources that are smaller 

than those covered by the federal requirements.

Craft state or local regulatory programs or permits 

that impose on sources the most stringent standards 

that appear to be feasible. For example, this might 

include the imposition of Best Available Control 

Technology (BACT)-level standards on existing 

sources, even in the absence of a modifi cation that 

would trigger New Source Review (NSR).

Through regulations or permits, set limits on sulfur 

levels in coal and oil for sources that burn these fuels.

For sources that are permitted to burn more than one 

type of fuel, impose permit conditions that strictly 

limit the extent to which they may burn the more 

polluting fuel.

Consider the imposition of regulatory standards that 

can be met by most, but not necessarily all, sources to 

which the standard is applicable, with an opportunity 

•

•

•

•

•
 Introduction 3

for sources to demonstrate that the standards 

are technically infeasible in light of particular 

circumstances.

Adopt a state-level cap-and-trade program or 

participate in a regional trading program for a 

particular source category or group of source 

categories.

The discussion above applies to stationary and area 

sources, but not to mobile sources, as to which all states 

other than California have less leeway to impose their own 

standards. For new vehicles, states are limited to federal 

standards or to the more stringent standards that California 

has adopted. For existing onroad vehicles, all states can 

impose their own standards; although for existing nonroad

vehicles, they once again have only the choice of federal or 

California standards. 

However, by no stretch of the imagination does this mean 

that states should overlook the possibilities for mobile 

source strategies as a way of tackling PM2.5 nonattainment. 

As we discuss in the chapters that follow, states have a 

range of opportunities for addressing these sources. 

Energy Effi ciency

The rising cost of fossil fuels has focused the nation’s 

attention on the opportunities for reducing fuel 

consumption, including energy effi ciency measures, 

some of which are addressed in this report. For example, 

Chapter 18, Residential Fuel Combustion and Electricity 

Use, discusses several demand-side effi ciency measures. 

However, other source categories surely present 

opportunities for increased effi ciency that regulators 

should not overlook. 

On the supply side, energy effi ciency measures involve 

increasing the effi ciency of the fuel combustion process or 

of the way the fuel is utilized. At a conventional power 

plant, two-thirds of the potential energy in the fuel burned 

to produce electricity is inevitably lost to waste heat. 

Meanwhile, facilities burn additional fuel to satisfy their 

thermal needs (for hot water, space heating and the like). 

Combined heat and power (CHP or cogeneration) facilities 

located at or near a facility address this problem by 

recovering the waste heat and putting it to productive use. 

CHP systems can achieve overall effi ciencies of greater 

than 80 percent (Elliott, 1999; EPA, 2000). In the late 

1990s, 9 percent of this country’s electricity came from 

cogeneration plants, although a number of other countries 

garnered a much higher percentage: Denmark (40 percent), 

Finland and the Netherlands (30 percent each), the Czech 

Republic (18 percent), and Germany (15 percent) (Elliott, 

1999).

A number of the industry sectors we profi le in this 

•

report are candidates for cogeneration. The petroleum 

refi ning and pulp and paper industries already employ 

cogeneration to some degree, but the practice has room to 

grow further in those industries and others, such as cement 

manufacturing and iron and steel production (Elliott, 

1999). 

There are unquestionably disincentives to the development 

of CHP in this country (e.g., high prices for excess power 

that CHP projects sell to the grid, long tax depreciation 

periods for CHP equipment), although increasing fuel 

prices make cogeneration more attractive. Environmental 

regulators can reverse some of the disincentives; for 

example, by writing air pollution permits on an electricity 

(and, where appropriate, thermal) output rather than on a 

heat input basis, to encourage effi ciency in the use of fuel.

This Report

As indicated, this report addresses a broad range of source 

categories. These sources do not represent the entire 

inventory of PM2.5, SO2 and NOx emissions, although they 

do cover a large share of the national inventory. Each 

source category chapter provides an overview of the 

category, background on the technical as opposed to the 

policy options for reducing emissions, and an overview of 

existing regulatory authority (with the regulatory authority 

issues discussed up-front in the mobile source chapters 

because of the preeminence of preemption considerations). 

Each chapter concludes with a discussion of state and local 

policy measures. 

Additionally, the report has two separate technology 

chapters—one on boiler and another on diesel engine 

technologies. The boiler technology chapter informs the 

industrial and commercial boiler and electric generating 

unit chapters, as well as the chapters on other source 

categories that burn process fuels (e.g., pulp and paper). 

The chapter on diesel engine technologies is useful for 

understanding the three mobile source chapters, as well 

as substantial portions of the airport and marine port 

chapters.

The report begins with the The Highlights of the source 

category chapters. Although these do not substitute for 

the detail provided in each chapter, they cull the most 

signifi cant emissions reductions opportunities. Prior 

to the sector-specifi c chapters, Chapter 2 discusses the 

health effects of PM2.5, Chapter 3 discusses the national 

emissions inventory, and Chapter 4 provides an overview 

of the Clean Air Act. 

References

Elliott, R. Neal, and M. Spurr, American Council for an 

Energy-Effi cient Economy. Combined Heat and Power: 
4 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Capturing Wasted Energy, May 1999. http://www.aceee.

org/pubs/IE983.htm.

U.S. Environmental Protection Agency (EPA). Combined 

Heat and Power, January 2000. http://yosemite.epa.gov/

oar/globalwarming.nsf/UniqueKeyLookup/SHSU5BPLD4/

$File/combinedheatandpower.pdf.

State and Territorial Air Pollution Program Administrators 

and the Association of Local Air Pollution Control Offi cials 

(STAPPA/ALAPCO). Restrictions on the Stringency 

of State and Local Air Quality Programs: Results of a 

Survey by the State and Territorial Air Pollution Program 

Administrators (STAPPA) and the Association of Local 

Air Pollution Control Offi cials (ALAPCO), December 17, 

2002. http://www.4cleanair.org/stringency-report.pdf.
 Chapter 1 - The Highlights 5

Introduction

The highlights that follow identify the most signifi cant 

emissions reduction opportunities for fi ne particulate 

matter (PM2.5) and PM2.5-precursors from each of the 

industries addressed in the sector-specifi c chapters of this 

report. We emphasize, however, that local considerations 

need to inform local choices about the sources and 

pollutants to control in order to address PM2.5 pollution 

most effectively.

Additionally, almost all of the items we identify in The 

Highlights fall within the purview of environmental 

regulators. However, in certain instances we have included 

strategies that would require action by other agencies or 

branches of government, such as measures to reduce total 

vehicle miles traveled. We have done so only when these 

strategies are particularly effective.

Industrial and Commercial Boilers 

Industrial and commercial boilers represent about 40 

percent of all energy use in the industrial and commercial 

sectors. Although most commercial boilers are small (less 

than 10 million British thermal units per hour (MMBtu/

hr)), very large industrial boilers (greater than 250 

MMBtu/hr) account for almost half of industrial boiler 

capacity. However, in many fuel and size categories, 

standards for PM, sulfur dioxide (SO2) and nitrogen 

dioxides (NOx) emissions from industrial and commercial 

boilers are less stringent than standards for the same 

Chapter 1

The Highlights

pollutant emissions from electric generating unit (EGU) 

boilers. Although there may be reasons in individual cases 

why the most stringent EGU boiler limits are not feasible 

for industrial and commercial boilers, those limits suggest 

an appropriate starting point for consideration of limits for 

industrial and commercial boilers larger than 250 MMBtu/

hr, and even for those larger than 100 MMBtu/hr.

Apart from the differences in EGU and industrial/

commercial boiler standards, there are enormous 

disparities in terms of the stringency of various emissions 

standards for PM, SO2 and NOx for industrial and 

commercial boilers. These disparities suggest that there is 

signifi cant room for improvement in the emissions profi le 

of this source category. For example:

In certain industrial and commercial boiler categories 

(e.g., new residual oil-fi red boilers between 10–100 

MMBtu/hr, new and existing natural gas-fi red 

boilers larger than 5 MMBtu/hr), state Best Available 

Control Technology (BACT) determinations set 

much tighter PM emissions limits than do the federal 

Maximum Achievable Control Technology (MACT) 

standards. For example, compare the BACT limit of 

0.02 pounds per MMBtu (lb/MMBtu) to the MACT 

standard of 0.03 lb/MMBtu for new residual oilfi red boilers between 10–100 MMBtu/hr; and the 

BACT limit of 0.007 lb/MMBtu to the absence of any 

MACT limit for new natural gas-fi red boilers larger 

•
6 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

than 5 MMBtu/hr. 

The same kind of disparity appears between the new 

federal New Source Performance Standards (NSPS) 

for SO2 emissions from industrial and commercial 

boilers built after February 2005 and the NSPS 

for SO2 from existing industrial and commercial 

boilers. For example, the SO2 standard for new coalfi red boilers between 100–250 MMBtu/hr is 0.20 

lb/MMBtu, compared to 1.2 lb/MMBtu for existing 

units of that size. The SO2 standard for new residual 

oil-fi red boilers greater than 100 MMBtu/hr is 0.32 

lb/MMBtu, compared to 0.8 lb/MMBtu for existing 

boilers. State and local regulators will want to 

consider the feasibility of requiring existing sources 

to meet these more stringent standards.

Although wood-fi red boilers constitute 4 percent of 

industrial boiler capacity, they account for fully 20 

percent of industrial boiler PM2.5 emissions. Average 

uncontrolled PM2.5 emissions rates for wood-fi red 

industrial boilers are higher than those of any fossil 

fuel-fi red boilers. A recent BACT limit for PM for 

an existing wood-fi red EGU boiler sets the same limit 

as the MACT standard for PM emissions for new

wood-fi red industrial and commercial boilers (0.025 

lb/MMBtu). This limit is approximately three times 

more stringent than the MACT standard for PM from 

existing wood-fi red boilers industrial and commercial 

boilers (0.07 lb/MMBtu).

For industrial and commercial boilers burning 

natural gas and residual oil, the San Joaquin Valley 

Unifi ed Air Pollution Control District (UAPCD) has 

set some of the most stringent NOx emissions limits 

in the country. For example, it imposes a limit of 

0.007 lb/MMBtu on natural gas-fi red boilers greater 

than 5 MMBtu/hr, as compared to an NSPS of 0.3 lb/

MMBtu for natural gas-fi red boilers greater than 100 

MMBtu/hr. Also, the San Joaquin Valley UAPCD 

has NOx standards that apply to units as small as 

0.075 MMBtu/hr, while the federal NSPS apply only 

to units larger than 100 MMBtu/hr. 

State and local agencies have other options for limiting 

emissions from industrial and commercial boilers in 

addition to setting emissions limits. For example, 

Connecticut has set limits of 0.3 percent by weight on the 

sulfur content of fuel oil used by power plants (with the 

alternative of a 0.33 lb/MMBtu SO2 emissions rate), and 

these limits could be applied to boilers in other industry 

sectors. New York has set limits on the sulfur content of 

both oil and coal used by power plants and other sources. 

The limits vary by area within the state, with the lowest 

limits in New York City: (1) 0.30 percent sulfur by weight 

for residual oil, (2) 0.20 percent sulfur by weight for 

distillate oil, and (3) 0.2 lb of sulfur per MMBtu gross heat 

content for solid fuels.

•

•

•

States should also consider supporting regional multipollutant initiatives (aimed at SO2, NOx and mercury 

emissions from EGUs and large industrial boilers), such 

as the Clean Air Interstate Rule (CAIR)-Plus initiative of 

the Ozone Transport Commission (OTC) and the regional 

air quality initiative of the Lake Michigan Air Directors 

Consortium (LADCO), discussed in the EGU Highlights

below. 

Electric Generating Units

The electric power sector is one of the dominant sources 

of PM2.5, SO2 and NOx emissions in the U.S. Within the 

EGU sector, coal-fi red power plants account for the vast 

majority of emissions. Nationwide, EGUs account for 

almost 10 percent of the PM2.5 emissions, nearly 70 percent 

of the SO2 emissions, and more than 20 percent of the NOx

emissions from all source categories. In 2002, coal-fi red 

power plants were responsible for 92, 95 and 87 percent of 

EGU emissions of PM2.5, SO2 and NOx, respectively.

The average emissions rates for SO2 and NOx across all 

coal-fi red EGUs in the U.S. in 2002 were 0.94 lb/MMBtu 

and 0.40 lb/MMBtu, respectively. To put these average 

emissions rates in perspective, a typical baseload coal 

plant would generate about 33,000 tons of SO2 and 14,000 

tons of NOx annually at these rates. 

There are many opportunities for states and localities to 

regulate PM2.5 emissions and their precursors from EGUs 

far more stringently than EPA’s CAIR. In fact, several 

states have already passed laws or regulations aimed at 

reducing EGU emissions beyond federal requirements. 

Other states and localities may wish to adopt similar 

programs. For example, New Hampshire law requires 

EGUs to reduce their SO2 emissions 75 percent (based 

on a rate of 3.0 pounds per megawatt-hour (lb/MWh)) by 

December 2006, and their NOx emissions 70 percent (based 

on a rate of 1.5 lb/MWh) by the same date. Massachusetts 

regulations also limit coal plant SO2 emissions to roughly 

0.3 lb/MMBtu and NOx emissions to roughly 0.15 lb/

MMBtu within the next few years, well in advance of the 

second-phase CAIR caps. North Carolina law imposes 

similar limits, although with a later effective date.

STAPPA and ALAPCO have conducted an analysis 

identifying the emissions reductions that can be achieved 

from EGUs by applying BACT. The Associations 

concluded that EGUs could achieve emissions limits of 

0.10 lb/MMBtu for SO2 and 0.07–0.08 lb/MMBtu for NOx. 

States should also consider national and regional 

approaches to achieving more stringent and expeditious 

reductions than CAIR. STAPPA and ALAPCO’s strategy 

calls for a national SO2 cap of 1.26–1.89 million tons per 

year (as compared to a baseline of 10.6 million tons in 

2001) by 2013, and a NOx cap of 0.88–1.26 million tons 
 Chapter 1 - The Highlights 7

per year by the same date (as compared to a baseline of 4.7 

million tons in 2001). 

Additionally, regional groups like the OTC and LADCO 

are considering options that extend beyond CAIR and 

could include large industrial boilers. The OTC is 

evaluating a phased cap-and-trade program for SO2 and 

NOx. In Phase 1, which would be implemented on January 

1, 2009, the program would be based on an SO2 emissions 

rate of 0.24 lb/MMBtu, and a NOx emissions rate of 0.12 

lb/MMBtu. In Phase 2, which would be implemented 

beginning January 1, 2012, the caps would be ratcheted 

down based on an SO2 emissions rate of 0.14 lb/MMBtu 

and a NOx emissions rate of 0.08 lb/MMBtu. The Midwest 

Regional Planning Organization has been evaluating 

similar reduction targets, including a Phase 2 SO2 cap 

between 0.15 lb/MMBtu and 0.10 lb/MMBtu in 2013 and 

a Phase 2 NOx cap between 0.10 lb/MMBtu and 0.07 lb/

MMBtu in 2013.

State and local agencies have other options for limiting 

emissions from power plants in addition to setting 

emissions limits. For example, as detailed in The 

Highlights for industrial and commercial boilers, 

Connecticut and New York have both set limits on the 

sulfur content of fuel.

States should also consider options for promoting 

renewable energy sources and energy-effi cient power 

generation to meet future energy demands. The District 

of Columbia and 21 states have adopted Renewable 

Portfolio Standard (RPS) programs, requiring varying 

amounts of renewables in their electricity supply. For 

example, California requires 20 percent renewable 

generation by 2017, New York requires 25 percent by 

2013, and Pennsylvania requires 18 percent by 2020. 

(These percentages are not exactly comparable, because 

the states vary in the resources they defi ne as renewable.) 

States have also established funding initiatives to promote 

renewable energy projects. These programs can be an 

important complement to the approaches recommended 

above.

Pulp and Paper

The pulp and paper industry is divided into three 

segments: pulp making, paper making and converting 

operations. The pulp making process is the largest source 

of emissions, accounting for over 75 percent of the sector’s 

PM2.5, SO2 and NOx emissions. Over 80 percent of the 

pulp mills in the U.S. use the kraft pulping process. There 

are four primary sources of emissions from kraft pulping 

operations: power boilers, recovery furnaces, lime kilns 

and smelt dissolving tanks (SDTs). 

Power boilers dominate the emissions from pulp mills. 

The approaches discussed in Chapter 6, Industrial and 

Commercial Boilers, and in The Highlights for those 

sources, are equally applicable to power boilers used in the 

kraft pulping process.

There are MACT standards for PM emissions from 

recovery furnaces, lime kilns and SDTs. These standards 

are 40 to 85 percent more stringent for new sources than 

they are for existing sources. The MACT standards for 

new sources limit PM emissions to 0.034 grams per dry 

standard cubic meter (g/dscm) for recovery furnaces, 

0.023 g/dscm for lime kilns and 0.06 kilograms per 

megagram for SDTs. State and local regulators should 

consider evaluating the feasibility of requiring existing 

sources to meet these more stringent standards. For 

example, upgrades to electrostatic precipitators (ESPs) and 

replacement of wet scrubbers with ESPs can signifi cantly 

reduce PM emissions. Older model ESPs on recovery 

furnaces have collection effi ciencies close to 90 percent, 

while newer model ESPs have collection effi ciencies 

greater than 99 percent.

While there are federal standards for SO2 and NOx

emissions from power boilers at pulp and paper facilities, 

there are no federal NSPS and MACT standards for SO2

or NOx emissions from other pulping emissions sources. 

Although the options for reducing NOx emissions from 

these sources are more limited, signifi cant reductions 

in SO2 emissions from recovery furnaces and lime kilns 

at kraft pulp mills are feasible. Some facilities have 

successfully lowered SO2 emissions from recovery 

furnaces by reducing the sulfur content of the processbased fuels and by regulating temperatures in the furnace 

to minimize SO2 formation. Where these techniques are 

not practical or successful, facilities should consider using 

a wet scrubber for SO2 control. 

Much like a number of the other industry sectors we have 

discussed, pulp and paper manufacturers are candidates 

for facility-wide emissions caps for PM, SO2 and NOx, 

on account of the number of their emissions sources 

and potential reduction strategies. In fact, the MACT 

standards for PM emissions from recovery furnaces, SDTs 

and lime kilns already include the option of a facility-wide 

emissions limit as an alternative to compliance with unitspecifi c standards. If regulators pursue the cap approach 

for all three pollutants, they should consider including 

power boilers, in light of their contribution to the overall 

emissions profi le of these facilities.

Cement Manufacturing

The largest source of emissions in cement manufacturing—

and the centerpiece of the process—is the kiln. Cement 

kilns generate over 40 percent of the PM emissions and 

more than 80 percent of both the SO2 and NOx emissions 

associated with cement manufacturing. 
8 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

More than 80 percent of the burners used to heat cement 

kilns use coal, and the remainder use other fossil fuels or 

waste materials combined with fossil fuels. A signifi cant 

portion of the NOx emissions and the SO2 emissions 

come from this fuel combustion, although raw material 

composition also infl uences SO2 emissions signifi cantly. 

PM emissions come from fuel combustion and from the 

handling, grinding and storing of raw materials, clinker 

and the fi nal product.

States and localities have signifi cant opportunities to 

reduce SO2 and NOx emissions from cement operations, 

especially in light of the fact that there are currently no 

federal NSPS for this industry. Recent advancements in 

selective non-catalytic reduction (SNCR) technology make 

it suitable for use on cement kilns. Although there is only 

one SNCR device currently installed at a cement plant in 

the U.S., there are over 32 SNCR systems installed on kilns 

in Germany and many more in the rest of Europe. 

Recently approved permits in Florida have required the 

installation of SNCR controls with low-NOx burners 

(LNBs) and multi-staged combustion as BACT for NOx. 

BACT determinations that include all three technologies 

include NOx limits as low as 1.95 pounds per ton (lb/ton) 

of clinker (30-day average). Recent BACT determinations 

that do not include SNCR, but do include LNBs and multistaged combustion have NOx limits of 2.8–5.52 lb/ton of 

clinker. 

Sulfur levels in the fuel and raw materials heavily 

infl uence SO2 emissions rates from cement kilns. Cement 

kiln systems have highly alkaline internal environments 

that can absorb up to 95 percent of potential SO2 emissions. 

For this reason, even if they burn fuels that are relatively 

high in sulfur, preheater/precalciner kilns can virtually 

eliminate SO2 emissions. However, without the use of raw 

materials that are low in sulfur, uncontrolled emissions 

from preheater/precalciner kilns can be as high as 7.6 lb/

ton of clinker. By contrast, recent BACT determinations 

have set SO2 limits ranging from 0.20 to 2.16 lb/ton of 

clinker. In the absence of add-on controls, the use of lowsulfur raw materials is essential for the control of SO2.

Where the process itself does not achieve satisfactory 

SO2 emissions levels, wet fl ue gas desulfurization (FGD) 

technology can provide an SO2 control effi ciency of 

90–99 percent. Use of wet FGD systems in the cement 

manufacturing process can be complicated by particle 

build-up and clogging, but LADCO has concluded that 

these problems are manageable if the FGD device is 

installed downstream of an effi cient fabric fi lter. Of more 

than 100 cement plants in the country, only fi ve currently 

use wet scrubbers to control SO2, suggesting substantial 

opportunities for the industry to improve its emissions 

profi le. Dry FGD technology (not recommended for 

wet kilns) and lime spray injection are other SO2 control 

options, although they are less effective.

Federal NSPS and MACT standards limit particulate 

emissions from cement manufacturing. Recently 

promulgated MACT standards set PM limits for cement 

kilns using hazardous waste as fuel. These standards are 

substantially more stringent than the NSPS and MACT 

standards for PM for fossil fuel-fi red cement kilns. State 

and local regulators should require kilns that burn fuels 

other than hazardous waste to meet the more stringent 

standards, absent a showing that a particular plant cannot 

achieve these levels.

Additionally, recent BACT determinations for PM and 

particulate matter less than 10 micrometers (PM10) for 

combined kiln and clinker cooler emissions are about a 

quarter of the federal NSPS and MACT PM limits for 

combined kiln and clinker cooler emissions for cement 

facilities burning non-hazardous materials. 

Almost all stages of the manufacturing process include 

particle capture devices, most frequently fabric fi lters 

or ESPs, each with control effi ciencies of 95–99 percent. 

Control device collection effi ciencies can be improved by 

rebuilding ESPs with a larger number of collection areas 

and increased treatment times, and using fabric fi lters in 

combination with ESPs.

Regulators should consider as a model the rules recently 

promulgated by the South Coast Air Quality Management 

District (AQMD) to control fugitive PM emissions 

from cement manufacturing. Among other things, the 

rules require the enclosure of many parts of the cement 

manufacturing operation, and mandate the ventilation of 

enclosed areas to a control system. 

Iron and Steel

Coke making

Coke making involves the heating of coal in coke ovens at 

high temperatures until all volatile components evaporate. 

The best way to reduce emissions from coke making is 

to reduce the amount of coke produced. Pulverized coal 

or other fossil fuels may substitute for some portion of 

the coke used in the blast furnace. Further, a number of 

relatively new coke production processes reduce coking 

emissions (e.g., using a non-recovery coke battery), and 

technologies exist to produce iron and steel without using 

coke at all.

In the production of coke, it is important to avoid large 

temperature fl uctuations (thereby reducing damage to the 

coke oven battery) and incomplete coking (which results 

in “green pushes”), in order to minimize PM emissions. 

Emissions should also be controlled by staged charging, 

which involves introducing coal into the oven at a 
 Chapter 1 - The Highlights 9

controlled rate.

All quench towers should have baffl es that are cleaned 

periodically, and clean water should be used for quenching. 

Dry quenching is expensive, but is even more effective in 

reducing emissions. 

SO2 emissions can also be reduced by desulfurizing coke 

oven gas before it is burned. Only 11 of the 16 byproduct 

recovery coke plants do so, and state and local regulators 

should consider requiring this. The U.S. Steel plant in 

Allegheny County, Pennsylvania has managed to produce 

coke oven gas with hydrogen sulfi de levels between 15-20 

grains per 100 dry standard cubic feet.

Allegheny County stands at the forefront in a number 

of other respects, and regulators elsewhere may wish to 

consider its rules. Allegheny County sets instantaneous 

limits for visible emissions from doors, charging, lids and 

offtake systems, as well as for PM emissions from pushing 

and combustion stacks. Because coking emissions 

can be controlled to some degree by a careful program 

of maintenance—e.g., door cleaning and rebuilding, 

application of sealing material on coke oven doors—

workers are required to undergo extensive training. 

Indiana has also set opacity limits for bypass heat 

exchanger stacks and for pushing controls.

Iron making

The blast furnace converts iron ore into a more pure and 

uniform iron. Casting, the main source of blast furnace 

emissions, is the process of periodically removing molten 

iron and slag from the furnace. About half of U.S. blast 

furnaces control casthouse emissions with covered runners 

and by evacuating emissions through capture hoods ducted 

to a baghouse. The half of U.S. blast furnaces that do 

not have these controls have opportunities for signifi cant 

reductions. 

Steel making

Most integrated mills use basic oxygen furnaces, or 

BOFs, for the fi nal step of making iron into steel. The 

oxygen blow portion of the furnace cycle, which involves 

introducing oxygen into the furnace to refi ne the iron, 

accounts for the largest share of emissions, followed 

by tapping (pouring the molten steel into a ladle) and 

charging (the addition of molten iron and metal scrap to 

the furnace).

Primary emissions during oxygen blow periods are 

typically controlled with an open hood directed to an 

ESP or wet scrubber, or by a closed hood ducted to a wet 

scrubber. According to EPA, fabric fi lters would provide 

signifi cantly better PM control, but are not used at any 

facility in the U.S. Upgrading old scrubbers to scrubbers 

with a higher pressure drop and upgrading ESPs will also 

reduce primary emissions.

About half of BOF shops rely on the primary collection 

system to capture some of the fugitive emissions from 

BOF operations. Regulators should consider requiring 

the addition of secondary collection systems, which 

would signifi cantly enhance the pollution control of these 

furnaces. 

Sinter plants

There are only fi ve sinter plants in the U.S. These plants 

convert fi ne-sized raw material into an agglomerated 

product (sinter) to be charged into a blast furnace. 

Although all the plants operate sinter coolers to cool the 

product prior to storage, only one has a control device. The 

other four vent directly to the atmosphere. Requiring these 

four to install control devices for their coolers represents 

the most signifi cant emissions reduction opportunity for 

sinter plants.

State and local agencies should also consider Indiana’s 

regulations on the oil and grease content of sinter plant 

feedstock.

Minimills

Minimills bypass the coke and iron making processes by 

producing steel from metal scrap using electric arc furnace 

(EAF) technology. All plants should be required to use a 

baghouse to control primary emissions from scrap melting, 

as well as hoods and baghouses to control emissions from 

the ladle metallurgy process and from the argon oxygen 

decarburization vessel.

All minimills control fugitive emissions from charging, 

tapping and melting with baghouses, but ten plants are 

subject to opacity limits for fugitive emissions that are 

not as stringent as the NSPS. Regulators should consider 

adopting opacity limits for these plants that are at least as 

stringent as the NSPS requirements.

Petroleum Refi neries

Petroleum refi neries are complex facilities with numerous 

sources of air pollution, including boilers, process heaters, 

catalytic cracking units, internal combustion engines 

and fl ares. Although no single control technology or 

combination of controls will be applicable to all cases, 

facilities have a wide range of opportunities for reducing 

emissions.

Because of the large number of refi nery emissions sources 

and potential reduction strategies, state and local agencies 

should consider adopting facility-wide emissions standards 

for refi nery combustion units, allowing sources to average 
10 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

emissions rates across units. California’s Bay Area AQMD 

limits NOx emissions from boilers, steam generators and 

process heaters to a refi nery-wide NOx standard of 0.033 

lb/MMBtu. The facility-wide approach has allowed 

refi nery operators to customize compliance strategies for 

their facilities. For example, one San Francisco Bay Area 

refi nery reduced its process heater NOx emissions to less 

than 20 parts per million (ppm), and its power boiler NOx

emissions to less than 25 ppm.

In Texas, the Houston-Galveston region established a NOx

cap-and-trade program in 2000 that included the region’s 

refi neries. The goal of the program is to reduce industrial 

point source NOx emissions by an average of 80 percent 

from 1997 levels. Like facility-wide emissions standards, 

the trading approach allows sources fl exibility to address 

a large number and variety of emissions sources. In 

response to this fl exibility, refi nery operators implemented 

a wide range of strategies, including the retrofi t of large gas 

turbines with selective catalytic reduction (SCR) systems; 

the decommissioning of smaller, lower effi ciency steam 

boilers; and the conversion of generating units to combined 

heat and power systems.

The federal NSPS for catalytic cracking units and sulfur 

recovery plants are outdated. In lieu of, or in combination 

with, a comprehensive facility-wide approach, state and 

local agencies should consider adopting more stringent PM 

and SO2 emissions standards for these units, and should 

impose stringent NOx standards. (There are no NSPS 

for NOx for these units.) Since 2000, EPA has entered 

into consent decrees with 83 refi neries (17 companies), 

comprising 77 percent of the nation’s refi ning capacity. 

State permitting authorities should look to the emissions 

limits and control options required by the consent decrees 

in developing updated PM, SO2 and NOx emissions 

standards for catalytic cracking units, sulfur recovery 

plants and other units. For example, several of the consent 

decrees require refi nery owners to install wet gas scrubbers 

on their fl uidized catalytic cracking units in order to limit 

both PM and SO2 emissions.

State and local agencies should also consider adopting 

rules to better manage PM, SO2 and NOx emissions from 

fl aring activities. The Bay Area AQMD and the South 

Coast AQMD have adopted similar rules addressing fl are 

gas emissions that should inform other state rulemakings. 

Both rules, which require the preparation of fl are gas 

minimization plans, were preceded by requirements to 

monitor and report fl are gas emissions. These monitoring 

requirements led to signifi cant emissions reductions. 

For example, in 2004, refi neries in the South Coast 

area reported an 80 percent reduction in SO2 emissions 

associated with fl aring since they began monitoring and 

reporting their fl are gas emissions. Subsequent Bay Area 

AQMD and South Coast AQMD rules require fl are gas 

minimization plans and are designed to reduce emissions 

further.

Diesel Trucks and Buses

Although fewer in number than cars, diesel-powered 

trucks and buses have a greater impact on air quality. NOx

emissions from these vehicles account for about 20 percent 

of all NOx emissions, including stationary, area and mobile 

sources. Additionally, almost all of the PM emissions from 

trucks and buses are PM2.5.

More stringent federal NOx standards for new onroad 

heavy-duty diesel engines will be phased in between 2007 

and 2010, and more stringent federal PM standards will 

go into full effect in the 2007 model year. Also, federal 

regulations will reduce sulfur levels in onroad diesel fuel in 

2006. These new standards will have a dramatic effect on 

emissions from this sector in the future. However, trucks 

and buses have a long lifetime, meaning that state and local 

regulators will have signifi cant opportunities for at least a 

decade to control emissions from older existing vehicles 

(and there is no Clean Air Act preemption affecting state 

and local regulation of existing trucks and buses).

State and local emissions programs imposing emissions 

standards on existing trucks and buses fall into three 

categories: (1) voluntary; (2) mandatory for all vehicles of 

a given type (e.g., all heavy-duty trucks above a certain 

weight); and (3) mandatory for certain types of vehicles that 

the government buys or that are covered by government 

contracts (e.g., school buses, refuse haulers). States can 

also increase taxes and registration fees for older vehicles 

to encourage their retirement.

Voluntary replacement and retrofi t programs need 

funding in order to be successful. Most such programs 

provide grant funding, as do California’s Carl Moyer 

Memorial Air Quality Standards Program, the Texas 

Emissions Reduction Program, and programs in New 

York, New Jersey and the Puget Sound area. Some vehicle 

replacements and retrofi t technologies have short payback 

periods because they result in fuel savings, and are good 

candidates for revolving loan programs.

There are also numerous examples of both kinds of 

mandatory programs—those that apply to all vehicles of 

a given type and those that apply to vehicles subject to 

government contracts. California has required retrofi ts of 

various fl eets. New York City has mandated the retrofi t 

of several types of heavy-duty vehicles, including school 

buses, city-licensed sightseeing buses and garbage trucks 

used for all city contracts.

Regulators should also adopt idling limitations to reduce 

the fuel use and emissions of trucks and buses, as more 

than 20 cities and states have done. These regulations 
 Chapter 1 - The Highlights 11

ban unnecessary idling (for example, idling a truck while 

making deliveries) for more than a specifi ed period of 

time. By contrast, the idling done by long-haul truckers 

(sometimes for as much as 12 hours per day) is necessary 

to maintain heating, cooling and other amenities while 

drivers are resting in their sleeper cabs. For these vehicles, 

idling limitations require modifi cations to individual trucks 

or the addition of infrastructure at truck stops. However, 

these investments are likely to have short payback periods 

because of the resulting fuel savings, and may be amenable 

to funding through revolving loan programs. EPA has 

issued guidance on State Implementation Plan (SIP) credit 

for programs that reduce the idling attributable to the use 

of sleeper cabs.

Programs that encourage the maintenance of proper tire 

infl ation will reduce fuel use and emissions, especially 

for long-haul truckers. Moreover, lowering speed limits 

where possible, and enforcing existing speed limits, will 

also cut emissions by reducing fuel use. Diesel trucks and 

buses that lower their speed from 65 to 55 miles per hour 

(mph) use approximately 20 percent less fuel.

Nonroad Equipment

The New York City emissions inventory for 1999 is 

illustrative of the air pollution problems associated with 

nonroad equipment: 45 percent of PM emissions and 26 

percent of NOx emissions from all mobile sources in New 

York City came from construction equipment.

Nationally, nonroad diesel equipment contributes about as 

much to the inventory of NOx emissions as do trucks and 

buses—about 20 percent of the total, including stationary, 

area and mobile sources. Also like the emissions from 

trucks and buses, almost all of the PM from the nonroad 

category is PM2.5. Although the Clean Air Act preempts 

states from regulating some kinds of nonroad equipment 

(e.g., aircraft, certain small engines), they nonetheless 

have signifi cant opportunities to reduce emissions from 

this sector.

Like the diesel standards for trucks and buses, EPA 

emissions limits for nonroad equipment are becoming 

more stringent, but at a slower pace; it will take until 2016 

for the onroad and nonroad diesel standards to achieve 

general parity. In light of the lag in regulations and the 

long lifetime of this equipment (as much as 40 years), 

existing nonroad equipment is an even better target than 

onroad vehicles for retirement and retrofi t programs. 

Similar to trucks and buses, state programs imposing 

emissions standards on existing nonroad equipment 

fall into three categories: (1) voluntary; (2) mandatory 

for all vehicles of a given type (e.g., portable engines, as 

California has done); and (3) mandatory for certain types 

of vehicles that the government buys or that are covered 

by government contracts (e.g., construction equipment on 

public projects). 

As in the onroad context, voluntary replacement and 

retrofi t programs need a funding source to be successful, 

and many of the same grant programs apply to onroad 

and nonroad vehicles. Grant programs in California, 

Texas and Washington State have funded hundreds of 

nonroad emissions reduction projects. And once again, 

technologies with short payback periods from fuel savings 

are good candidates for revolving loan programs.

Mandatory retrofi t and replacement programs that apply to 

all vehicles of a given type are more diffi cult (but feasible) 

to apply in the nonroad context than the onroad context 

for a number of reasons. For one thing, privately owned 

nonroad equipment is usually not required to be registered 

with the state. Another reason is that states cannot adopt 

their own standards for existing nonroad equipment 

(which is different from the Clean Air Act provisions for 

trucks and buses and light-duty vehicles)—the Clean Air 

Act confi nes states to California or federal standards. 

However, California has recently adopted mandatory 

retrofi t requirements for portable diesel engines used in a 

variety of equipment, and states are free to mandate these 

standards. The California rules include requirements for 

agricultural pumps, airport ground support equipment, 

oil drilling rigs and portable generators. The rules 

are intended to result in a 95-percent reduction in PM 

emissions from these engines by 2020. 

The opportunity to encourage or mandate the use of 

reduced-sulfur fuels arises from the lag time in federal 

regulations for nonroad diesel fuels as compared to 

onroad diesel fuels. Federal regulations will reduce sulfur 

levels in onroad diesel fuel in 2006, but sulfur limits for 

most nonroad diesel fuel will be phased in between 2007 

and 2010. As a result, the use of reduced-sulfur onroad 

diesel fuel in nonroad equipment between now and 2010, 

or the use of other alternative fuels, can reduce direct PM 

emissions and, more importantly, will make retrofi t devices 

more effective. (California regulations will also reduce 

sulfur in onroad diesel fuel in 2006. The adoption of 

California diesel fuel rules involves some complexities, but 

would allow a state to mandate the use of reduced-sulfur 

onroad diesel fuel in nonroad equipment, regardless of 

whether the equipment is used for government services.)

Idling restrictions are somewhat less feasible on nonroad 

than on onroad vehicles for a number of reasons. However, 

this is not true for switcher yard locomotives, which 

often idle excessively, and states and local areas should 

consider adopting these restrictions. Voluntary programs 

in a number of states and local areas, including California, 

Chicago, the Seattle-Tacoma area and Texas provide 

funding for locomotive idle reduction programs. The 

payback periods on these programs are often short (6–20 
12 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

months). EPA has issued guidance on taking SIP credit for 

locomotive idle reduction programs. 

Light-Duty Cars and Trucks

Light-duty cars and trucks, the majority of which are 

gasoline fueled, contribute about 16 percent of the NOx

emissions from all sources—stationary, mobile and area 

combined. But these vehicles contribute much less direct 

PM2.5 than do heavy-duty diesel vehicles, and the SO2

contribution of this sector will fall dramatically beginning 

in 2006, when allowable fuel sulfur levels for gasoline are 

reduced. 

Starting with the 2004 model year, EPA implemented 

stricter emissions standards for cars and light trucks, as 

did California. Given the relatively fast turnover rate of 

the light-duty fl eet, these standards will have an effect in 

the short term, as new vehicles replace older ones. EPA 

estimates that annual NOx emissions from light-duty 

vehicles will fall by 66 percent by 2020 due to normal fl eet 

turnover, despite a 20-percent increase in annual vehicle 

miles traveled.

Largely because of the turnover rate of these vehicles, 

retrofi ts will not be the best strategy for reducing emissions 

from the light-duty (as compared to the heavy-duty diesel) 

fl eet. Instead, strategies that increase the vehicle turnover 

rate or encourage fl eets and individuals to purchase the 

cleanest vehicles available will accelerate reductions. 

Many states and local areas (including the Bay Area, 

California, Colorado, Connecticut, Illinois, Maine, New 

Jersey and New York) have adopted such programs, and 

others should consider doing so. Strategies include: 

monetary incentives for individuals and fl eet 

owners to make clean choices, including the choice 

of alternative fuel vehicles when buying new 

vehicles (e.g., scrappage programs, tax rebates, tax 

exemptions, reductions in vehicle registration fees); 

and

non-monetary incentives for the purchase of cleaner 

vehicles (e.g., permission to use high-occupancy 

vehicle (HOV) lanes, exemption from state emissions 

tests, free parking at street meters and municipal 

parking lots).

About ten states have adopted California’s low-emissions 

vehicle (LEV) standards for new cars, which are more 

stringent than EPA’s standards. Other states should 

consider adopting these LEV II standards instead of EPA’s 

Tier 2 standards. 

Burning less fuel means less air pollution. States and 

localities can adopt legislation and policies to reduce 

vehicles miles traveled and otherwise reduce fuel use and 

•

•

emissions from the light-duty fl eet, such as:

increasing or improving public transportation;

encouraging non-emitting modes of transportation by 

building or improving bicycle paths and pedestrian 

walkways;

adopting and publicizing employee commuting 

benefi ts;

establishing HOV lanes;

enhancing traffi c management and reducing 

congestion; and

keeping maximum highway speeds to 60 mph (by 

reducing maximum speed limits where possible, and 

enforcing existing speed limits).

Even states without a federal inspection and maintenance 

(I&M) mandate are free under federal law to adopt an 

I&M program. A committee of the National Research 

Council of the National Academies of Sciences concluded 

that well-structured I&M programs are one of the most 

cost-effective vehicle strategies for reducing vehicle 

emissions of those it evaluated. In light of the fact that 

a small proportion of vehicles create a disproportionate 

share of emissions, regulators should consider adopting 

I&M programs designed to target these vehicles.

Airports

The numerous urban PM2.5 areas that are home to one or 

more major airports will be interested in options to address 

the increasing level of PM and NOx emissions from 

airports. Although states have no authority to regulate 

aircraft engines, which dominate airport emissions 

inventories, they have numerous opportunities to reduce 

emissions from airport ground service equipment and 

ground transportation vehicles.

Airport ground service equipment includes baggage 

tugs, belt loaders and aircraft pushback tractors, many of 

which are diesel fueled. These pieces of equipment are 

candidates for the same kinds of emissions reductions 

strategies that apply to nonroad equipment generally, 

including the retrofi t and replacement of older vehicles 

and the use of onroad reduced-sulfur diesel fuel or other 

alternative fuels.

Ground transportation fl eets are also candidates for 

retrofi t and replacement; these include the predominantly 

diesel-fueled shuttle buses that ferry passengers to airport 

parking and car rental lots and to hotels. For example, the 

South Coast AQMD has required airport fl eet operators 

to purchase or lease alternative-fueled vehicles when 

adding or replacing vehicles. In addition, airports should 

•

•

•

•

•

•
 Chapter 1 - The Highlights 13

adopt and enforce anti-idling rules for diesel buses, which 

generate signifi cant excess emissions while waiting, at 

idle, for passengers.

As is the case for marine ports, the optimum mix of control 

strategies will vary from airport to airport, depending on 

fuel availability, existing infrastructure, existing vehicle 

technologies and other factors. However, the variety of 

emissions sources and the range of available reduction 

strategies also make airports good candidates for programs 

that cap their overall emissions. Facility-wide emissions 

caps encourage the comprehensive evaluation of the most 

cost-effective control options. For example, the Texas 

Commission on Environmental Quality (TCEQ) negotiated 

a voluntary agreement with the Dallas/Fort Worth 

International Airport to reduce NOx emissions. As part 

of the agreement, the air carriers agreed to reduce ground 

service equipment NOx emissions by 75 percent relative to 

1996 levels. TCEQ also negotiated a voluntary agreement 

with Continental Airlines, Southwest Airlines and the 

City of Houston to reduce NOx emissions. Massport, the 

operator of Boston’s Logan Airport, established a cap 

on airport NOx emissions; any emissions increases that 

result from airport activities must be offset by emissions 

reductions on site or near the airport, or by the purchase of 

emissions reduction credits. 

The Federal Aviation Administration’s Voluntary 

Airport Low Emissions (VALE) Program provides 

funding for LEVs, refueling and recharging stations, gate 

electrifi cation and other airport air quality improvement 

measures at commercial service airports in nonattainment 

and maintenance areas. 

Marine Ports

Over 30 of the largest U.S. ports are in areas that are in 

nonattainment for PM2.5, ozone, or both. While emissions 

inventories vary from port to port, the Ports of Long 

Beach and Los Angeles are instructive: their mobile 

sources account for about 25 percent of the total PM from 

all mobile sources in the Los Angeles area.

Most of the PM and NOx emissions from ports come from 

marine vessels: ocean-going ships (which states cannot 

regulate), auxiliary engines on these ships, and commercial 

harbor craft. Cargo-handling equipment is the biggest 

land-based mobile source contributor. All of these sources 

are diesel powered, and almost all of their PM emissions 

are PM2.5. 

As home to large numbers of heavy-duty diesel vehicles, 

marine ports are candidates for the same emissions 

reduction strategies that otherwise apply to trucks, 

buses and nonroad equipment. These include the retrofi t 

and replacement of older vehicles, the use of onroad 

reduced-sulfur diesel fuel or other alternative fuels in 

nonroad equipment, and limits on vehicle idling. Some 

port vehicles—like Category 1 marine engines larger 

than 600 horsepower (e.g., tugboats) and some material 

handling equipment—are particularly good candidates 

for repowering because of the greater fuel effi ciency of 

replacement engines. Moreover, because of their typical 

governance structure (public or semi-public), many ports 

are in a good position to implement some or all of these 

measures or to require that terminal operators do so. This 

is because, as previously noted, mandatory replacement 

and retrofi t programs are more feasible if they apply 

to nonroad equipment that is subject to government 

purchasing or contracting requirements.

Their localized nature also provides opportunities for 

marine ports to make or require changes to nonroad 

vehicles that might otherwise be infeasible. For example, 

several ports (e.g., the Ports of Los Angeles and of Juneau, 

Alaska) have made the infrastructure improvements that 

allow the “hotel loads” on large ships to be supplied by 

land-side electric power (called “cold-ironing”) while they 

are docked, rather than with on-board auxiliary engines. 

(Cruise ships typically spend up to a full 24 hours docked, 

while exchanging passengers; and some cargo vessels take 

100 hours or more to unload.) Similarly, ports from New 

York to Seattle have replaced diesel-powered cranes with 

electric cranes.

Marine ports have a range of other options for reducing 

emissions, such as programs that encourage ships to 

operate at lower speeds near the coast (e.g., programs at 

the Port of Long Beach and the Port of Los Angeles); and 

operational changes that reduce truck queuing and idling 

(e.g., measures at the Georgia Ports Authority and the Port 

of Virginia). Because of the variety of options available, 

marine ports, like airports, are excellent candidates 

for programs that cap their overall emissions, thereby 

facilitating the identifi cation of the most cost-effective 

reduction opportunities. 

Residential Fuel Combustion and 

Electricity Use

The residential source category produces PM2.5 and PM2.5-

precursor emissions on-site from the direct consumption 

of fuels—such as natural gas, liquefi ed propane gas, 

kerosene, fuel oil, coal and wood. Additionally, an even 

larger share of the emissions attributable to the source 

category occurs off-site, at fossil fuel-fi red power plants. 

In light of emissions considerations and widespread 

concern regarding the rising costs of fossil fuels, residential 

energy-effi ciency programs should be part of the strategy 

for delivering air quality improvements. State and local 

regulators have a number of options in this regard.

Regulators should consider promoting the tax incentives 
14 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

contained in the Energy Policy Act of 2005 and also 

adopt complementary state and local programs to further 

encourage the deployment of energy-effi cient technologies. 

For example, under the Energy Policy Act, households that 

purchase and install energy-effi cient windows, insulation, 

and heating and cooling equipment can receive a tax credit 

of up to $500 beginning in January 2006.

If they have not already done so, state and local agencies 

should consider regulating NOx emissions from residential 

furnaces, one of the largest on-site sources of NOx

emissions in the residential category. In California, 

several air districts, including the South Coast AQMD, the 

Bay Area AQMD and the San Diego County Air Pollution 

Control District, have adopted NOx emissions standards 

for natural gas-fi red central furnaces. These rules suggest 

a starting point for establishing state standards. However, 

regulators should also evaluate the feasibility of more 

stringent standards, in light of the fact that the standards 

in California were fi rst established in 1978, and burner 

technology has made signifi cant advances in NOx control 

since that time.

States that are reliant on home heating oil should regulate 

its sulfur content to 0.05 percent sulfur by weight (500 

parts per million (ppm)). Currently in the U.S., heating 

oil for residential use has an average sulfur content of 

about 0.20–0.25 percent. Switching to low sulfur content 

fuel could eliminate 75–80 percent of the SO2 emissions 

generated by residential oil heating systems, as well as 80 

percent of PM2.5 emissions. Switching to low-sulfur oil 

can also reduce maintenance and service requirements. 

The American Society for Testing and Materials, 

an international voluntary standards development 

organization, has approved a Low Sulfur No. 2 Heating 

Oil specifi cation, and industry trade associations have 

advocated a switch to low-sulfur heating oil.

Replacing an older wood stove with an EPA-certifi ed 

model can signifi cantly reduce a home’s direct PM2.5

emissions. This is particularly true as the costs of heating 

oil and natural gas rise and households become more 

reliant on wood stoves for heating. Programs in Libby, 

Montana and Allegheny County, Pennsylvania, initiated in 

2005, provide a model for other communities considering 

a wood stove changeout initiative. The Energy Policy 

Act of 2005 provides tax incentives for high-effi ciency 

wood stoves. States can promote this incentive and also 

supplement the program with funding of their own. Other 

strategies should be considered as well (e.g., requiring all 

wood stoves that are not EPA-certifi ed to be removed prior 

to the sale of a property).

State and local agencies should consider regulating PM 

emissions from residential outdoor wood-fi red boilers, 

which generate large quantities of smoke. There are an 

estimated 100,000 of these units in the U.S., providing 

an alternative source of energy in the face of rising fossil 

fuel prices. Local news stories and growing numbers of 

complaints to local health agencies provide evidence of the 

adverse impact of these boilers on local air quality. 

Regulators should also consider banning the burning of 

household garbage, which generates emissions of toxics 

and particulates. The Western Lake Superior Sanitary 

District has developed an extensive toolkit for local 

offi cials to assist them in evaluating and implementing 

alternatives.

Commercial Cooking

Charbroiling generates over 80 percent of total PM2.5

from the commercial cooking sector. The sector’s PM2.5

emissions account for 6 percent of the total direct PM2.5

emissions generated by all point source categories in 1999 

(e.g., power plants and industrial facilities).

Commercial cooking establishments use two types of 

charbroilers: underfi red and chain-driven. Most emissions 

(74 percent) come from the use of underfi red charbroilers, 

although regulatory efforts have focused on control of the 

chain-driven charbroilers used predominantly by fast-food 

restaurants.

State and local air pollution control agencies should 

consider regulating PM emissions from new and existing 

chain-driven charbroilers. Some areas have already 

adopted regulations. In California, the South Coast AQMD 

requires operators of both new and existing chain-driven 

charbroilers to install a catalytic oxidizer (but allows 

alternative control devices if they are equally effective). 

Catalytic oxidizers appear to reduce PM emissions by over 

80 percent, and are highly cost-effective ($1,680–$2,800 

per ton of PM and VOCs reduced).

Control options are available for reducing emissions from 

underfi red charbroilers, but are more costly than those 

available for chain-driven charbroilers. Because the South 

Coast AQMD has concluded that none of the options 

available for controlling PM emissions from underfi red 

charbroilers meets its cost-effectiveness criteria, the 

agency has not regulated this source category.

Commercial cooking establishments consume substantial 

amounts of energy, some portion of which is wasted. For 

example, charbroilers generally idle at a rate close to their 

full heat input to be ready for the next round of cooking. 

Charbroilers contribute to the cooling loads in a kitchen, 

as they generate excess heat. Further investigation of 

strategies for reducing the energy use of charbroilers is 

warranted.
 Chapter 1 - The Highlights 15

Fugitive Dust

Fugitive dust refers to particles, most commonly derived 

from soil, that are lifted into the air by human activities 

and natural forces, such as agricultural tilling, motor 

vehicle use and wind. The major sources of fugitive dust 

are paved and unpaved roads, agricultural operations, 

construction projects and wind erosion from both 

agricultural and non-agricultural lands.

There are two basic options for controlling fugitive PM 

emissions from paved roads: (1) prevention strategies 

aimed at reducing the amount of dirt and sand deposited to 

roadways; and (2) mitigation strategies like street sweeping, 

which remove the material after it has been deposited on 

the road surface. Unpaved roads can be paved or can be 

addressed with surface treatments. The primary options 

for reducing fugitive dust from agricultural operations 

include limiting tillage activities during windy conditions 

and reducing tillage in various ways (e.g., by adopting lowtill agricultural practices).

In designing a dust control program, state and local 

agencies should consider focusing on targeted programs in 

order to minimize the costs of control, such as, paving only 

the most heavily traveled roadways or prioritizing them for 

dust control measures. The San Joaquin Valley UAPCD 

imposes a 25 mph speed limit on unpaved roads with over 

25 vehicles per day. The District also requires the paving 

of unpaved roads and road shoulders, with priority given 

to roads with the highest traffi c volumes. Clark County, 

Nevada requires control measures such as paving for 

existing unpaved roads with at least 150 vehicles per day.

Cars and trucks sometimes deposit dirt or debris onto 

the surface of a paved road when leaving a worksite or 

unpaved road. This “trackout” can be controlled with the 

construction of gravel beds or other control devices, which 

remove the dirt prior to the vehicle’s entering the roadway. 

For example, the South Coast AQMD requires trackout 

control devices for construction projects exceeding fi ve 

acres.

For paved roads, street cleaning operations can be 

targeted to minimize the costs of control by focusing on 

cleaning anti-skid materials and cleaning dirt deposited 

on a busy road as a result of wind and rain. Apart from 

these targeted strategies, the cycle of particle deposition 

on road surfaces and subsequent resuspension in the air 

will generally outpace efforts to keep roads swept, thereby 

limiting their effectiveness as a control option.

With respect to agricultural operations, the South Coast 

AQMD limits fugitive dust by promoting soil conservation 

practices such as low-till agriculture. The South Coast 

AQMD also limits tilling activities during high wind 

events: tilling and mulching activities must cease when 

wind speeds are greater than 25 mph.
16 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Airborne particulate matter (PM) has been associated 

with adverse effects on human health since early in the 

20th century. In fact, episodes of acute PM pollution that 

took place decades ago in different parts of the world 

spurred the development of many of the fi rst air pollution 

guidelines. During such episodes—including at the 

Meuse Valley in Belgium in 1930; Donora, Pennsylvania 

in 1948; and London, England in 1952—extremely high 

PM levels were associated with a dramatic increase in 

daily mortality. In Donora, 20 residents died and 7,000 

people—half the town’s population—were hospitalized 

with diffi culty breathing due to a poisonous mix of 

airborne particulates and gases from the smokestacks of 

the local zinc smelter and other sources. This tragedy, in 

particular, shocked the U.S. and marked a turning point in 

the nation’s complacency about air pollution and its effects 

on human health.

PM is the generic term for a broad class of chemically 

and physically diverse substances that exist as discrete 

particles (liquid droplets or solids) over a wide range of 

sizes. Particles originate from a variety of anthropogenic 

stationary and mobile sources as well as from natural 

sources. Particles may be emitted directly or formed in the 

atmosphere by transformations of gaseous emissions such 

as sulfur dioxide (SO2), nitrogen oxides (NOx) and volatile 

organic compounds. The chemical and physical properties 

of PM vary greatly with time, region, meteorology and 

source category, thus complicating the assessment of 

health and welfare effects.

PM can be divided into (and is currently regulated under) 

two size ranges: PM2.5 and PM10. PM2.5 denotes particles 

equal to or less than 2.5 micrometers (μm) in diameter.1

PM10 particles are those with diameters equal to or less 

than 10 μm. PM2.5 can be further divided into ultrafi ne 

particles (particles less than approximately 0.1 μm in 

diameter). Throughout this discussion, references to 

PM2.5 include all particles equal to or less than 2.5 μm in 

diameter, including ultrafi ne particles. 

PM2.5 or “fi ne” particles are of particular concern to human 

health. One-twentieth the width of a human hair, these 

fi ne particles can be inhaled deep into the gas-exchange 

regions of the lung, where the thin-walled alveoli replenish 

the blood with oxygen.

“Coarse” particles, covering the range from about 2.5 

to 10 μm in diameter, also cause adverse health effects. 

Some of these coarse particles are generated naturally 

by sea-salt spray, wind and wave erosion, volcanic dust, 

windblown soil and pollen. They are also produced by 

human activities such as construction, demolition, mining, 

road dust, tire wear and industrial processes involving the 

grinding and crushing of rocks or metals. Larger coarse 

particles tend to settle out of the air more rapidly than fi ne 

particles and will usually be found relatively close to their 

source. Fine particles, however, can be transported long 

1. In this report, particle size or diameter refers to a normalized measure 

called “aerodynamic diameter,” which accounts for the irregular shape 

and varying density of most particles.

Chapter 2

Effects of Particulate Matter on 

Human Health and the Environment
 Chapter 2 - Effects of Particulate Matter on Human Health and the Environment 17

distances by wind and weather, traveling thousands of 

miles from where they were formed.

As discussed later in this report, the concentration and 

composition of particle pollution in the atmosphere 

vary by time of year and by location and are affected by 

several aspects of weather, such as temperature, humidity 

and wind. For example, PM2.5 in the eastern half of the 

U.S. contains more sulfates than those in the West, while 

PM2.5 in southern California contains more nitrates than in 

other areas of the country. In the East, PM2.5 values are 

highest from July through September, while in most of the 

West, PM2.5 values are highest in the winter. Carbon is a 

substantial component of PM2.5 everywhere. On a local 

scale, researchers have observed high concentrations of 

PM in close proximity to major roads and highways. 

Numerous studies have linked PM (both PM2.5 and 

PM10) air pollution to a broad range of cardiovascular 

and respiratory health endpoints. Newer studies report 

associations between short-term exposure to various 

indicators of PM and cardiopulmonary mortality, 

hospitalization and emergency department visits and 

respiratory symptoms. In addition, there is now evidence 

for associations with cardiovascular health outcomes, such 

as heart attacks and changes in blood chemistry. Children 

and the elderly, as well as people with pre-existing 

cardiovascular or respiratory diseases such as asthma, 

are particularly susceptible to health effects caused by 

PM. PM is also an effective delivery mechanism for other 

toxic air pollutants, which attach themselves to airborne 

particles. These toxics are then delivered into the lungs, 

where they can be absorbed into blood and tissue. To 

the extent that the studies referenced in this chapter 

refer specifi cally to PM2.5, PM10, or the PM size fraction 

between 10 and 2.5 μm, we have identifi ed the appropriate 

size range.

Biological Mechanisms

The health risk from an inhaled dose of PM depends on 

the size and characteristics of the particles inhaled. Size 

determines how deeply the inhaled particles will penetrate 

into the respiratory tract, where they can persist and 

cause respiratory and other damage. In general, only 

particles equal to or smaller than 10 μm in diameter (the 

PM10 fraction) can be inhaled deep into the lungs without 

fi rst being intercepted by the nose or pharynx. Particles 

deposited in the alveolar region (the air sacs of the lungs) 

can remain in the lungs for long periods of time because 

alveoli lack the mucus-lined clearance system of the 

trachea and bronchi. This presents a particular concern 

because the alveoli are where oxygen exchange to the 

blood takes place.

When a foreign material reaches the cells of the lung, 

macrophages (white blood cells that reside in the tissues 

and airspaces of the lung) and other protective cells 

respond to the threat by attempting to engulf, degrade 

and ultimately expel the invader. The precise biological 

mechanisms that lead to adverse health effects have not 

been well defi ned, although experimental observations 

have suggested several hypotheses. Particles in the lung 

will frequently result in an infl ammatory response, which 

can produce cell damage. Particles may also stimulate 

nerve cells in the underlying tissue, which in turn may 

affect the nervous system and its control of breathing, 

heart rate and heart rate variability. Ultrafi ne particles 

may themselves enter the blood stream to be transported 

to the liver, bone marrow and heart, with direct or indirect 

effects on organ function. Researchers have suggested 

that several physiological responses might occur in concert 

to produce health effects (EPA, 2005a). 

If it were known which properties of PM were responsible 

for the preponderance of adverse health effects, emissions 

and air quality standards could focus on controlling the 

particles that present the greatest risk. Thus far, however, 

the laboratory and fi eld evidence do not implicate one 

specifi c toxic quality of PM to the exclusion of others 

(EPA, 2005a). Qualities such as the size of the PM and 

the presence of certain chemical components (e.g., metals) 

appear to contribute to its toxicity. 

Short-Term Exposure

According to EPA, short-term exposure (hours or days) 

to PM2.5 and PM10 can aggravate lung disease, causing 

Source: American Lung Association

Fig. 2.1 The Human Respiratory System
18 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

asthma attacks and acute bronchitis, and may also increase 

susceptibility to respiratory infections. In people with 

heart disease, short-term exposures have been linked to 

heart attacks and arrhythmias. Healthy children and adults 

have not been reported to suffer serious effects from shortterm exposures, although they may experience temporary 

minor irritation when particle levels are elevated.

Particulate air pollution causes greater use of asthma 

medications and increased rates of school absenteeism, 

emergency room visits and hospital admissions. Other 

adverse effects can include coughing and wheezing. Shortterm increases in PM levels have been linked to:

death from respiratory and cardiovascular causes;

increased numbers of heart attacks, especially among 

the elderly and people with heart conditions;

infl ammation of lung tissue in young, healthy adults;

increased hospitalization for cardiovascular disease;

increased emergency room visits for patients 

suffering from acute respiratory ailments;

increased hospitalization for asthma among children;

increased severity of asthma attacks in children.

In the early 1990s, dozens of short-term community 

health studies from cities throughout the U.S. and around 

the world indicated that short-term increases in particle 

pollution were associated with adverse health effects as 

outlined above.

The National Morbidity, Mortality and Air Pollution 

Study (NMMAPS) is the largest multi-city analysis of the 

short-term effects of PM air pollution on human health. 

The study included analyses of PM10 effects on mortality 

in 90 U.S. cities (Samet, 2000a, 2000b; Dominici, 2003). 

Additional, more detailed, analyses were conducted based 

on a subset of the 20 largest U.S. cities (Samet, 2000b).

The NMMAPS used a uniform methodology to evaluate 

the relationship between mortality and PM10 for the 

different cities, and synthesized the results to provide a 

combined estimate of effects across the cities. The authors 

reported statistically signifi cant associations between both 

cardiorespiratory mortality and mortality from all causes, 

and PM10 concentrations. The risk estimates for deaths 

from cardiorespiratory causes were somewhat larger 

than those for deaths from all causes. The results of the 

NMMAPS assessment held up using different modeling 

approaches and adjustments for gaseous co-pollutants. 

Another major multi-city study used data from ten of the 

NMAPS cities where daily PM10 monitoring data were 

available (Schwartz, 2003). Again, the authors reported 

•

•

•

•

•

•

•

a statistically signifi cant association between PM10 and 

total mortality, with a reported health risk larger than that 

reported in the NMMAPS study. The authors of the study 

suggest that the availability of more frequent monitoring 

data may partly account for the differences.

Epidemiologic studies have reported associations between 

short-term exposures to ambient PM (often using PM10) 

and measures of changes in cardiac function such as 

arrhythmia, alterations in electrocardiogram patterns, and 

heart rate or heart rate variability changes (Brook, 2004). 

These new epidemiologic fi ndings offer some insight into 

potential biological mechanisms that underlie associations 

between short-term PM exposure and cardiovascular 

mortality and hospitalization previously reported in the 

literature.

The American Heart Association (AHA) has conducted 

an extensive review of the medical literature on the health 

effects of particle pollution and issued a statement in 2004 

concluding that exposure to PM2.5 air pollution contributes 

to the development of cardiovascular diseases (AHA, 

2004). Although the increase in relative risk for heart 

disease associated with PM2.5 for an individual was deemed 

small in comparison to the impact of such cardiovascular 

risk factors as high blood pressure and high cholesterol, 

PM was identifi ed as a serious public health problem due 

to the very large number of people affected and because 

exposure occurs over an entire lifetime.

Long-Term Exposure

Long-term exposure, such as that experienced by people 

living for years in areas with high PM levels, has been 

associated with problems like reduced lung function 

and the development of chronic bronchitis—and even 

premature death. Other symptoms range from premature 

births to serious respiratory disorders, even when particle 

levels are very low. Year-round exposure to particulate 

pollution has also been linked to:

slowed lung function growth in children and 

teenagers;

signifi cant damage to the small airways of the lungs;

increased risk of death from lung cancer;

increased risk of death from cardiovascular disease.

Three major studies of the chronic effects of PM exposure 

have linked increases in mortality and long-term exposure 

to PM: the Six Cities, American Cancer Society (ACS), 

and California Seventh Day Adventist (AHSMOG) studies. 

More recently there has been a comprehensive reanalysis 

of data from the Six Cities and ACS studies, and new 

analyses using updated data from the AHSMOG and ACS 

•

•

•

•
 Chapter 2 - Effects of Particulate Matter on Human Health and the Environment 19

studies.

The reanalysis of the Six Cities and ACS studies confi rms 

their original fi ndings, suggesting an association with both 

total and cardiorespiratory mortality and exposure to PM2.5

(Krewski, 2000). Researchers performed an extensive 

sensitivity analysis using alternative statistical methods 

and considered the role of 20 potential confounders—such 

as other pollutants, climate and socioeconomic factors—

on study results. The study identifi ed higher educational 

status as a factor associated with reduced risk to air 

pollution exposure and reported an association between 

SO2 pollution and mortality. 

The expanded analysis of the ACS cohort study found 

signifi cant associations between long-term exposure to fi ne 

particles (using various averaging periods for air quality 

concentrations) and premature mortality from all causes, 

cardiopulmonary diseases and lung cancer (Pope, 2002). 

In both the reanalyses and extended analyses of the ACS 

cohort study, long-term exposure to the PM size fraction 

between 10 and 2.5 μm was not signifi cantly associated 

with mortality (Krewski, 2000; Pope, 2002). Of all the 

long-term exposure studies, EPA places greatest weight on 

the results of the Six Cities and ACS studies because of the 

data and methodologies used.

Populations at Risk

Individuals with heart or lung disease, older adults 

and children are considered to be at greater risk from 

particulate air pollution, especially when they are 

physically active. Physical activity causes individuals to 

breathe faster and more deeply, taking more particles into 

their lungs.

People with heart or lung disease—such as coronary 

artery disease, congestive heart failure and asthma or 

chronic obstructive pulmonary disease—are at increased 

risk because particles can aggravate these diseases (EPA, 

2003). Individuals with diabetes may also be at increased 

risk because they are more likely to have underlying 

cardiovascular disease.

Older adults are at increased risk, perhaps due to 

undiagnosed heart or lung disease or diabetes (EPA, 2003). 

Many studies show that when particle levels are high, 

older adults are more likely to be hospitalized and to die of 

aggravated heart or lung disease.

Children are at increased risk from exposure to PM for 

several reasons: their lungs are still developing; they spend 

more time at high activity levels; and they are more likely 

to have asthma or acute respiratory diseases (EPA, 2003).

It appears that the risk associated with PM exposure 

varies throughout a lifetime and is generally higher in 

early childhood, lower in healthy adolescence and young 

adulthood, and higher again in middle age through old age 

as the incidence of heart and lung disease and diabetes 

increases. Factors that increase the risk of heart attack, 

such as high blood pressure and elevated cholesterol levels, 

also may increase the risk associated with particulate 

exposure. In addition, scientists are evaluating new 

studies that suggest that exposure to high particle levels 

may also be associated with low birth weight in infants, 

pre-term deliveries, and possibly fetal and infant deaths 

(EPA, 2003).

Environmental Effects

The particles linked to serious health effects are also a 

major cause of visibility impairment in many parts of the 

U.S. Particles in the air reduce the distance at which one 

can see the color, clarity and contrast of distant objects 

because these particles scatter and absorb light. In many 

parts of the U.S., pollution has reduced visual range by 

70 percent from natural conditions (EPA, 1997). In the 

East, the current range is only 14 to 24 miles, compared 

to a natural visibility range of 90 miles. In the West, the 

current range is 33 to 90 miles, versus a natural visibility 

range of 140 miles (EPA, 1997). (Natural visibility in the 

East is lower than in the West, in part because of higher 

relative humidity, which causes some particles to become 

more effi cient at scattering light.)

PM2.5 can remain suspended in the air and travel long 

distances. For example, exhaust from a diesel truck in 

Los Angeles can end up over the Grand Canyon, where 

one-third of the haze comes from Southern California 

(EPA, 1997). Emissions from a Los Angeles oil refi nery 

can form particles that in a few days will affect visibility 

in Colorado’s Rocky Mountain National Park. Twenty 

percent of the haze problem on the dirtiest days in that 

park is attributed to emissions generated in Los Angeles 

(EPA, 1997). 

In the eastern U.S., reduced visibility is attributable 

mainly to secondary PM formed in the atmosphere from 

SO2 emissions. Although these secondary particles also 

account for a major portion of particulate loading in the 

West, primary emissions from sources like wood smoke 

and NOx emissions from motor vehicles and other sources 

contribute a larger percentage of the total particulate 

loading in the West.

In addition to affecting visibility, airborne particles can 

also lead to ecosystem damage. The most signifi cant 

PM-related ecosystem effects result when the long-term, 

cumulative deposition of nitrates and sulfates exceeds the 

natural buffering or storage capacity of the ecosystem and 

affects the nutrient status of the ecosystem, usually by 

indirectly changing soil chemistry, populations of bacteria 
20 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

involved in nutrient cycling, and/or populations of fungi 

involved in plant nutrient uptake. Nitrogen and sulfur in 

varying amounts are necessary and benefi cial nutrients 

for most organisms. However, excessive amounts of 

these nutrients from atmospheric deposition can lead to 

unintended ecosystem changes such as species shifts, 

loss of species richness and diversity, and impacts on 

threatened and endangered species.

In addition to altering ecosystem chemistry, particulate 

pollution also causes damage to vegetation directly. 

Experiments on seedling and sapling trees have shown 

signifi cant damage to leaf surface structures after exposure 

to simulated acid rain or acid mist (resulting primarily from 

the PM-precursors SO2 and NOx) at pH levels of 3.5 (EPA, 

2005a).2 Epicuticular waxes, which function to prevent 

water loss from plant leaves, can be destroyed by acid rain 

in a few weeks. The proper functioning of epicuticular 

wax in conifers is especially crucial because of their 

longevity and evergreen foliage. For example, red spruce 

seedlings, which have been extensively studied, appear 

to be more sensitive to acid precipitation (mist and fog) 

than other species (EPA, 2005a). Other direct responses 

of forest trees to acid precipitation include increased 

permeability of leaf surfaces to toxic materials, water, 

and disease agents; increased leaching of nutrients from 

foliage; and altered reproductive processes. All of these 

effects weaken trees, leaving them more susceptible to 

other stresses (e.g., extreme weather, pests and pathogens).

Airborne particles can also cause soiling and other damage 

to materials like concrete and limestone. The effects of 

PM on materials have been investigated for metals, wood, 

stone, painted surfaces, electronics and fabrics. Particulate 

pollution may soil and discolor these materials, reducing 

their aesthetic appeal. It may also cause other physical and 

chemical degradation of materials through the action of 

acidic particles.

PM NAAQS Review

As discussed in Chapter 3, EPA is required by the Clean 

Air Act to conduct periodic reviews of the National 

Ambient Air Quality Standards (NAAQS) for criteria 

pollutants, including PM. EPA must determine whether 

the latest scientifi c information suggests a need to 

revise the standards. In addition, the Act also requires 

an independent scientifi c review committee to provide 

scientifi c and technical advice to the EPA Administrator 

on issues related to the NAAQS. The Clean Air Scientifi c 

Advisory Committee (CASAC) has performed this 

function since the 1980s.

On January 17, 2006, EPA published its proposal for 

2. The initials pH stand for “potential of Hydrogen” — a measure of how 

acidic or alkaline a substance is. Acids have pH values under seven and 

alkalis have pH values over seven.

addressing the PM NAAQS. Among other things, the 

Agency proposed lowering the level of the 24-hour PM2.5

standard from 65 micrograms per cubic meter (μg/m3) to 

35 μg/m3, retaining the level of the annual PM2.5 standard 

at 15 μg/m3

, and setting a new 24-hour standard for PM10- 2.5

at 70μg/m3. EPA also proposes to exempt agricultural 

sources, mining sources and similar sources of crustal 

material from control in meeting the standards.

Prior to the Agency’s proposal on the PM NAAQS, EPA’s 

staff recommendations—which represent an intermediate 

step between the Agency’s detailed scientifi c review 

(embodied in the PM criteria document) and the policy 

decisions that the Administrator must ultimately make—

concluded that the current standards are not suffi ciently 

protective and should be tightened (EPA, 2005a). On the 

whole, CASAC members agreed with most of the EPA 

staff recommendations (EPA, 2005b). Most notably, the 

Committee agreed with EPA staff that the primary 24-hour 

and annual PM2.5 standards should be revised to provide 

greater public health protection.

In justifying its recommendations, the staff paper pointed 

to several studies demonstrating associations between 

cardiovascular mortality and morbidity and short-term 

PM2.5 exposure at levels below the current standard. For 

instance, while the current annual standard is 15 μg/m3, 

three studies have demonstrated increased mortality in 

areas where PM2.5 concentrations ranged between 13 and 

14 μg/m3. Three other studies demonstrate an increase in 

emergency department visits in areas with a mean PM2.5

concentration at or below 12 μg/m3. In addition, risk 

assessments demonstrate that morbidity would remain 

high and thousands of premature deaths would occur even 

if urban areas across the country attained the current PM2.5

standard. While the Agency is not required by statute to 

set standards that will eliminate all risk, the standards must 

protect public health with an adequate margin of safety.

The current PM NAAQS review process will continue 

in tandem with states’ efforts to achieve the current 

standards. EPA is under a court order to fi nalize its 

decision by September 2006.

References

American Heart Association (AHA). American Heart 

Association Scientifi c Statement: Air Pollution Is Serious 

Cardiovascular Risk, June 1, 2004. www.americanheart.

org/presenter.jhtml?identifi er=3022282.

Brook, R.D., B. Franklin, W. Cascio, Y. Hong, G. Howard, 

M. Lipsett, R. Luepker, M. Mittleman, J. Samet, S.C. 

Smith, Jr, and I. Tager. “Air Pollution and Cardiovascular 

Disease: A Statement for Healthcare Professionals from 

the Expert Panel on Population and Prevention Science 

of the American Heart Association,” Circulation 109: 
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2655-71, June 1, 2004. http://circ.ahajournals.org/cgi/

reprint/109/21/2655.pdf.

Dockery, D.W., C.A. Pope, X. Xu, J.D. Spengler, J.H. Ware, 

M.E. Fay, B.G. Ferris, and F.E. Speizer. “An Association 

Between Air Pollution and Mortality in Six U.S. Cities,” 

New England Journal of Medicine, 329:1753-9, December 

9, 1993. http://content.nejm.org/content/vol329/issue24/

index.shtml.

Dominici, F., A. McDermott, M. Daniels, S.L. Zeger, and 

J.M. Samet, Health Effects Institute. “Mortality Among 

Residents of 90 Cities,” Revised Analyses of Time-Series 

Studies of Air Pollution and Health, Special Report: 9-24, 

May 2003. www.healtheffects.org/Pubs/TimeSeries.pdf.

Hoek, G., B. Brunekreef, S. Goldbohm, P. Fischer, and 

P.A. van den Brandt. “Association between Mortality 

and Indicators of Traffi c-Related Air Pollution in the 

Netherlands: A Cohort Study,” The Lancet, 19: 1203-

9, 2002. www.thelancet.com/journals/lancet/article/

PIIS0140673602112803/fulltext.

Krewski, D., R.R. Burnett, M.S. Goldberg, K. Hoover, J. 

Siemiatycki, M. Jerrett, M. Abrahamowicz, W.H. White, 

Health Effects Institute. Reanalysis of the Harvard Six 

Cities Study and the American Cancer Society Study of 

Particulate Air Pollution and Mortality, July 2000. www.

healtheffects.org/Pubs/Rean-ExecSumm.pdf.

National Research Council, Committee on Estimating the 

Health-Risk Reduction Benefi ts of Proposed Air Pollution 

Regulations. Estimating the Public Health Benefi ts of 

Proposed Air Pollution Regulations, 2002. www.nap.edu/

books/0309086094/html.

Pope, C.A., M.J. Thun, M.M. Namboodiri, D.W. Dockery, 

J.S. Evans, F.E. Speizer, and C.W. Heath. “Particulate 

Air Pollution as a Predictor of Mortality in a Prospective 

Study of U.S. Adults,” American Journal of Respiratory 

Critical Care Medicine, 151: 669-74, 1995. http://ajrccm.

atsjournals.org/cgi/content/abstract/151/3/669.

Pope, C.A., R.T. Burnett, M.J. Thun, E.E. Calle, D. 

Krewski, K. Ito, and G.D. Thurston. “Lung Cancer, 

Cardiopulmonary Mortality, and Long-Term Exposure to 

Fine Particulate Air Pollution,” Journal of the American 

Medical Association, 287(9), March 6, 2002. http://jama.

ama-assn.org/cgi/reprint/287/9/1132.

Samet, J.M., S.L. Zeger, F. Domenici, F. Curriero, I. 

Coursac, D.W. Dockery, J. Schwartz, and A. Zanobetti, 

Health Effects Institute. “The National Morbidity, 

Mortality, and Air Pollution Study. Part I: Methods and 

Methodological Issues,” Research Report 94(1), June 2000. 

www.healtheffects.org/Pubs/Samet.pdf. (2000a)

Samet, J. M., S.L. Zeger, F. Domenici, F. Curriero, I. 

Coursac, D.W. Dockery, J. Schwartz, and A. Zanobetti, 

Health Effects Institute. “The National Morbidity, 

Mortality, and Air Pollution Study. Part II: Morbidity, 

Mortality, and Air Pollution in the United States,” 

Research Report 94(2), June 2000. www.healtheffects.org/

Pubs/Samet2.pdf. (2000b)

Samet, J.M., and M.J. Daniels, Health Effects Institute. 

“The National Morbidity, Mortality, and Air Pollution 

Study, Part III: Concentration–Response Curves and 

Thresholds for the 20 Largest US Cities,” Research Report

94(3), June 2004. www.healtheffects.org/Pubs/Daniels94-

3.pdf.

Schwartz, J. “Airborne Particles and Daily Deaths in 10 

US Cities,” Revised Analyses of Time-Series Studies of Air 

Pollution and Health, Special Report: 211-18, May 2003. 

www.healtheffects.org/Pubs/TimeSeries.pdf.

U.S. Environmental Protection Agency (EPA). Health and 

Environmental Effects of Particulate Matter, July 17, 1997. 

www.epa.gov/ttn/oarpg/naaqsfi n/pmhealth.html.

U.S. Environmental Protection Agency (EPA). Particle 

Pollution and Your Health (EPA-452/F-03-001), September 

2003. www.epa.gov/airnow/particle/cover.html.

U.S. Environmental Protection Agency (EPA). Air Quality 

Criteria for Particulate Matter, Vol. I of II (EPA/600/P99/002aF), October 2004. http://cfpub.epa.gov/ncea/cfm/

partmatt.cfm. (2004a)

U.S. Environmental Protection Agency (EPA). Air Quality 

Criteria for Particulate Matter, Vol. II of II (EPA/600/P99/002bF), October 2004. http://cfpub.epa.gov/ncea/cfm/

partmatt.cfm. (2004b)

U.S. Environmental Protection Agency (EPA). Review 

of the National Ambient Air Quality Standards for 

Particulate Matter: Policy Assessment of Scientifi c and 

Technical Information, OAQPS Staff Paper (EPA-452/R05-005), June 2005. www.epa.gov/ttnnaaqs/standards/pm/

data/pmstaffpaper_20050630.pdf. (2005a)

U.S. Environmental Protection Agency (EPA). EPA’s 

Review of the National Ambient Air Quality Standards for 

Particulate Matter (Second Draft PM Staff Paper, January 

2005): A Review by the Particulate Matter Review Panel 

of the EPA Clean Air Scientifi c Advisory Committee (EPASAB-CASAC-05-007), June 2005. www.epa.gov/sab/pdf/

casac-05-007.pdf. (2005b)
22 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Particulate matter (PM) is a complex pollutant that occurs 

throughout the U.S. in both urban and rural areas. Unlike 

other criteria pollutants, PM comprises a broad class of 

pollutants that includes a wide range of particle sizes and 

chemical constituents. Airborne particles can range in 

size from a few nanometers to upwards of 100 micrometers 

(μm) in diameter. As noted in Chapter 2, the term PM2.5

denotes particles with an aerodynamic diameter equal 

to or less than 2.5 μm. Some particles are liquid, some 

are solid and others contain a solid core surrounded by 

liquid. Common constituents include sulfates, nitrates, 

ammonium, elemental carbon, a variety of organic 

compounds, water, and inorganic substances (including 

metals, dust, sea salt and other trace elements) that are 

often categorized as “crustal” material. 

EPA and the states have established a network to monitor 

and record PM2.5 concentrations throughout the U.S. Data 

from this network show that national average particle 

concentrations have been declining. Despite progress 

to date, however, areas throughout the eastern U.S. and 

California exceed EPA’s National Ambient Air Quality 

Standards (NAAQS) for PM2.5.

In this chapter, we discuss the characteristics of ambient 

PM, including size and chemical composition. We also 

discuss the sources that contribute to ambient PM2.5

concentrations.

Characteristics of PM

PM air pollution is often discussed in terms of particle 

size because of the distinct characteristics (origin, 

chemical species and atmospheric behavior) associated 

with different particle size classes. In the discussion 

that follows, we distinguish among three particle sizes: 

(1) coarse particles in the range of about 2.5 to 10 μm in 

diameter; (2) fi ne particles (excluding ultrafi ne particles) in 

the range of about 0.1 to 2.5 μm in diameter, sometimes 

called accumulation mode particles; and (3) ultrafi ne 

particles less than approximately 0.1 micrometers in 

Chapter 3

Fine Particulate Matter 

and Precursor Emissions 
 Chapter 3 - Fine Particulate Matter and Precursor Emissions 23

diameter, sometimes called nuclei mode particles.1

Figure 3.1 shows a distribution of particle sizes typical 

of an urban environment in the U.S. As the fi gure 

shows, there is overlap among the different size classes. 

Formation mechanisms are also considered when 

distinguishing among categories of PM. Figure 3.1 reveals 

that particles larger than 0.1 μm in diameter account for 

most of the particle mass in U.S. urban areas. In terms of 

total number, however, most of the particles in urban areas 

are smaller than 0.1 μm in diameter (ultrafi ne particles).

Coarse Particles. In general, coarse PM—in the 

range of about 2.5 to 10 μm in diameter—is made up of 

primary particles, emitted directly from their sources as 

particles (EPA, 2005a). Most coarse particles result from 

the mechanical disruption of larger particles by crushing 

or grinding, from the evaporation of sprays or from the 

re-suspension of dust (crustal material). Specifi c sources 

include construction and demolition activities, mining and 

mineral processing, sea spray, wind-blown dust and the resuspension of settled biological material from soil surfaces 

and roads. Some combustion-generated particles, such as 

fl y ash, are also found in the coarse mode.

Fine Particles. In contrast to coarse particles, secondary 

1. The National Ambient Air Quality Standards for PM are defi ned 

based on sampling cut points: PM2.5 and PM10. PM2.5 denotes particles 

equal to or less than 2.5 μm in diameter. PM10 particles are those with 

diameters equal to or less than 10 μm. The basis for these cut points becomes apparent from the bi-modal distribution of the different particles 

sizes presented in Figure 3.1.

particles, produced by atmospheric transformation 

processes from precursor gases, dominate fi ne or 

accumulation mode particles (in the range of about 0.1 to 

2.5 μm in diameter). Particles in this size range generally 

are not emitted directly, but rather enter the atmosphere 

as ultrafi ne particles or gases that grow by coagulation 

or condensation and “accumulate” to this size range. 

Particles in this size range generally do not grow into 

coarse particles.

Ultrafi ne Particles. PM2.5 can be further divided into 

ultrafi ne particles (particles below approximately 0.1 μm 

in diameter) and nanoparticles (particles characterized 

Fig. 3.2 Particulate Matter Size Categories in Persepctive

90 micrometers in diameter

Fine Beach Sand Image courtesy of U.S. EPA, Offi ce of Research and Development

<2.5 micrometers in diameter

<10 micrometers in diameter

Human Hair

70 micrometers average diameter

PM10

PM2.5

Source: UCLA Institute of the Environment, 2001

Fig. 3.1 Particulate Matter Size Distribution in 

Urban Areas
24 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

too large to diffuse rapidly to surfaces or to other particles, 

but it is also too small to settle out or collide with stationary 

objects. These particles can be transported thousands of 

miles and remain in the atmosphere for days to weeks. 

Secondary particles serve as condensation nuclei for cloud 

droplet formation and are eventually removed from the 

atmosphere in falling raindrops. Gravity and collisions 

with surfaces eventually remove secondary particles that 

are not involved in cloud processes from the atmosphere.

by diameters of less than 50 nanometers or 0.05 μm). 

Ultrafi ne particles consist largely of primary combustion 

products, which undergo reactions in the atmosphere to 

form larger particles (fi ne or accumulation mode particles). 

Some of the formation processes that contribute to the 

growth of PM2.5 in the atmosphere include: (1) nucleation 

(i.e., gas molecules coming together to form a new 

particle), (2) condensation of gases onto existing particles, 

(3) coagulation of particles (i.e., the weak bonding of two or 

more particles into one larger particle), (4) uptake of water 

by hygroscopic components and (5) gas phase reactions 

that form secondary PM. These secondary formation 

processes can result in new particles or the addition of PM 

to pre-existing particles. Ultrafi ne particles have a very 

short atmospheric life, on the order of minutes to hours, 

because they readily convert to larger fi ne or accumulation 

mode particles.

Chemical Composition

The common chemical constituents of PM include sulfates, 

nitrates, ammonium, elemental carbon, a variety of 

organic compounds, water and crustal material (including 

metals, dust, sea salt and other trace elements). Sulfates, 

ammonium, elemental carbon and secondary organic 

compounds are found primarily in the PM2.5 range. Crustal 

material—including calcium, aluminum and silicon—is 

found primarily in the coarse particle range (larger than 

2.5 μm). Nitrates are found in both the PM2.5 and coarse 

particle size ranges.

Figure 3.3 describes the chemical composition of PM air 

pollution measured at a “supersite” location in the Los 

Angeles metropolitan area, comparing ultrafi ne, fi ne and 

coarse particles (Sardar, 2005). The data show the large 

crustal contribution to the coarse mode, contrasted with 

the large contribution of sulfates and nitrates to the fi ne 

mode.

Particles, or particle-bound water, can also act as carriers 

of toxic agents, such as metals and organic compounds 

(EPA, 2005a).

Fate and Transport

The fate and transport of particles in the atmosphere 

depend in part on their size. Ultrafi ne particles have a very 

short ambient residence time—on the order of minutes to 

hours—because they are likely to undergo gas-to-particle 

conversions. (These conversions mean they remain in the 

atmosphere, but in a different form.) Ultrafi ne particles 

are also small enough to be removed by diffusion to falling 

raindrops.

Secondary PM2.5, formed from ultrafi ne particles and gases 

remains suspended in the atmosphere longer because it is 

Fig. 3.3 Supersites Data Los Angeles, CA

Coarse Particles (2.5 to 10 μm)

Fine Particles (less than 2.5 μm)

Ultrafi ne Particles (less than 0.1 μm)

Source: Sardar, 2005
 Chapter 3 - Fine Particulate Matter and Precursor Emissions 25

In contrast, coarse particles can settle out from the 

atmosphere rapidly. As a result, they may be airborne 

from minutes to days depending on their size, atmospheric 

conditions and altitude. Larger coarse particles are not 

readily transported over long distances because they are 

generally too large to be carried by air streams and because 

they tend to be easily removed by gravity or impact, or 

are washed out of the atmosphere by rain. Smaller coarse 

particles can have longer atmospheric lifetimes and travel 

longer distances, especially in extreme circumstances. For 

example, dust storms in desert areas of Africa and Asia 

lift coarse particles to high elevations; the resulting dust 

clouds can be transported as far as North America.

Emissions Trends and 

Regional Characteristics

EPA and the states have established a network of air 

quality monitors to collect and measure PM10 and PM2.5

concentrations. The network has been recording PM10

concentrations since 1987 and PM2.5 concentrations since 

1999. The PM2.5 monitoring network includes roughly 

1,000 monitors, over 90 percent of which are located in 

urban areas.

EPA has measured a 10 percent decline in national annual 

average PM2.5 concentrations from 1999 to 2003 (EPA, 

2004). The Northeast is the only region that did not show 

a decline between these years: annual concentrations in 

the region rose slightly (about 1 percent) over the fi ve-year 

period. Outside of the Northeast, PM2.5 concentrations 

have trended lower during this period, with the largest 

improvement occurring in those regions that started with 

the highest concentrations. For example, average annual 

concentrations declined by 20 percent in the Southeast, 

16 percent in southern California and 9 percent in the 

industrial Midwest. By comparison, the upper Midwest, 

the Southwest and the Northwest—all of which had lower 

concentrations to begin with as compared to other regions 

of the country—posted more modest declines in PM2.5

concentrations.

Longer-term trends data are also available, although fewer 

monitors were in place prior to 1999. According to EPA, 

PM2.5 concentrations have declined on average by about 

30 percent over the past 25 years (EPA, 2004).

Recent monitoring data show the highest average PM2.5

concentrations in southern California and Pittsburgh, 

Pennsylvania. Elevated levels have also been recorded 

in urban areas throughout the Southeast, Northeast and 

industrial Midwest. Figure 3.4 shows the 39 areas that 

EPA has designated as exceeding the existing national air 

quality standard for PM2.5 based on air quality monitoring 

data from 2002 through 2004.

PM2.5 concentrations exhibit seasonal variability. For 

example, PM2.5 values in the eastern half of the U.S. are 

typically higher from July to September, when sulfates are 

more readily formed from sulfur dioxide (SO2) emissions. 

By contrast, PM2.5 concentrations tend to be higher in the 

winter months in many areas of the West—in part because 

fi ne particle nitrates are more readily formed in cooler 

weather, but also because the use of wood stoves and 

fi replaces produces more carbon.

The composition of PM2.5 varies geographically as well 

as seasonally. PM2.5 in the eastern U.S. is dominated by 

sulfates and carbon. PM2.5 in southern California contains 

more nitrates than in other areas of the country. Carbon 

is a substantial component of PM2.5 concentrations in all 

regions of the country. Figure 3.5 presents the average 

composition of urban PM2.5 by region.

There are no nationwide monitoring networks for ultrafi ne 

particles, although some studies have been conducted 

under the direction of EPA’s PM Supersites Program. 

Measurements taken at a Los Angeles monitoring station 

show that ultrafi ne particles make up a small portion of 

the PM concentration by mass. However, the number of 

ultrafi ne particles is signifi cantly larger than the number 

of coarse or fi ne particles. Studies have also found that 

ultrafi ne PM concentrations can be dramatically elevated 

Source: EPA, 2004

Fig. 3.5 Urban PM2.5 Composition by Region

Fig. 3.4 PM2.5 Nonattainment Areas

Source: EPA, 2005d
26 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

in close proximity to high vehicle traffi c areas and during 

busy traffi c periods (EPA, 2005a).

Emissions Sources

The sources of PM2.5 and PM2.5-precursor emissions are 

highly diverse, including both natural (biogenic) and 

human-made (anthropogenic) sources. Sources include 

motor vehicles, power plants, industrial facilities, wood 

stoves and fi replaces, forest fi res, sea salt, paved and 

unpaved roads and many others. 

Additionally, the contribution of various sources to 

PM2.5 formation varies by geography, time of year and 

even by time of day. As a result, national and regional 

inventories of PM2.5 and PM2.5-precursor emissions—

although suggestive of the primary contributors to ambient 

particulate concentrations—may not provide an accurate 

characterization of the major sources of emissions at a 

specifi c location or during a particular time period. 

The relationship between changes in precursor emissions 

and ambient PM2.5 concentrations, moreover, can be 

nonlinear. Generally, SO2 emissions reductions lead 

to reductions in concentrations of sulfate aerosols and 

nitrogen oxide (NOx) emissions reductions lead to 

reductions in nitrate aerosols. However, the direction 

and extent of changes in ambient PM2.5 concentrations as 

a result of a given level of emissions reduction vary by 

location and season and depend on fl uctuations in ammonia 

emissions and changes in prevailing meteorology and 

photochemistry. This complicates the task for state and 

local offi cials attempting to prioritize their PM2.5 control 

strategies.

With these cautionary statements in mind, we summarize 

the major sources of PM2.5 and PM2.5-precursor emissions 

from the sources addressed in this report, based on EPA’s 

National Emissions Inventory. A combination of databases 

(1999 and 2002) have been used to compile this summary, 

as indicated in Table 3.1.

Table 3.1, at the end of this chapter, presents the total 

primary PM2.5 emissions from all of the source categories 

addressed in this report. This table reports total primary 

PM2.5 emissions of 5,522,000 tons. Fugitive dust was the 

largest source of PM2.5 emissions, contributing 3,326,000 

tons (60 percent).

Table 3.1 also sets out estimates of total SO2 emissions 

from the source categories addressed in this report. As 

shown, emissions total 13,126,000 tons, with electric 

generating facilities responsible for 10,293,000 tons (78 

percent), and industrial point sources contributing another 

1,941,000 tons (15 percent).

Finally, Table 3.1 contains estimates of total NOx

emissions from the source categories addressed in this 

report. Emissions total 19,090,000 tons, with electric 

utilities contributing 4,700,000 tons (25 percent), highway 

vehicles contributing 8,167,000 tons (43 percent), and 

nonroad equipment (including marine vessels and airports) 

contributing 4,387,000 tons (23 percent).

This report does not present VOC emissions, although a 

subset of VOCs contribute to ambient PM2.5 concentrations. 

Also, ammonia from sources such as fertilizer and animal 

feed operations contributes to the formation of sulfates and 

nitrates that exist in the atmosphere as ammonium sulfate 

and ammonium nitrate. This report also does not cover 

ammonia emissions.

Uncertainties in the PM2.5 Inventory

The accuracy of the emissions estimates presented in this 

chapter and throughout this report vary. In some cases, 

we have a high degree of confi dence in the estimates. For 

example, most power plants continuously monitor and 

report SO2 emissions to EPA. In contrast, the estimates 

of direct PM2.5 emissions are less certain and likely to be 

changing in the coming years with further information. 

There are several reasons for the uncertainties.

First, there are limited measurements of PM2.5 emissions 

from stationary sources from which to estimate sourcespecifi c emissions factors. Many of the emissions stack 

tests that are the basis of currently available particle size 

distributions were conducted with methods that have since 

been shown to introduce errors. 

Second, EPA Method 5, the most common test method 

used for measuring PM emissions from stationary sources, 

measures total fi lterable particulates (TFP), not total PM10

or total PM2.5 specifi cally (EPA, 2005c). In most cases, 

sources estimate their PM2.5 emissions based on these 

measurements, rather than specifi cally testing for the fi ne 

fraction.

Third, researchers have suggested that sampling methods 

may be overstating the PM2.5 emissions rates of fugitive 

dust sources, such as agricultural operations. According 

to a recent study, the high volume cyclone/impactor system 

used to develop AP-42 emissions factors for fugitive dust 

sources has a positive bias (i.e., overestimates emissions) 

(Comis, 2004; WRAP, 2005).

Fourth, there are important distinctions among fi lterable 

PM2.5, condensable PM2.5 and total PM2.5. Filterable 

PM2.5 refers to those particles that are captured on the 

fi lter portion of a sampling train. Condensable particles 

are those that are in gaseous form in the stack but form 

solid or liquid particles soon after being released to the 
 Chapter 3 - Fine Particulate Matter and Precursor Emissions 27

atmosphere. Total PM2.5 includes both fi lterable and 

condensable particles.

There are several different methods (and variations of 

methods) used to measure PM emissions. In some cases, 

the test results refl ect only the fi lterable components in 

the fl ue gas. Additionally, the fi lterable components 

vary depending on the test method used. In particular, 

fi lter temperatures infl uence both the concentration of 

organic and inorganic vapors that can exist in a gas and 

also infl uence chemical reactions that occur in the air 

sample. At high temperatures, semi-volatile organic and 

inorganic compounds remain in the vapor phase (passing 

through the fi lter). At lower temperatures, these chemicals 

condense to become fi lterable PM. Additionally, at high 

temperatures, reactions between gases like ammonia and 

SO2 will be inhibited, so that they remain a gas and pass 

through the fi lter. At lower temperatures, these chemicals 

react, forming particulate-phase chemical compounds such 

as ammonium sulfate. For example, EPA Test Method 5B 

uses a high temperature fi lter (320 ± 25oF) when collecting 

a test sample. The sample is then heated in an oven at 

320oF (160oC) for six hours to volatilize any sulfuric acid 

that may have condensed on the fi lter.

There are many variations of EPA Method 5, which are 

intended to measure fi lterable PM. Several other EPA 

test methods are also intended to measure only fi lterable 

PM. EPA Method 202, on the other hand, is designed 

to measure condensable PM, by replicating the cooler 

temperatures that the fl ue gas encounters upon exiting 

a facility stack. Test Method 202 is intended for use in 

conjunction with a fi lterable PM test method to capture 

total PM emissions (EPA, 2005b).

As discussed previously, many emissions inventories 

do not use the results of site-specifi c source testing as 

the basis of their emissions inventory. Much of the 

emissions inventory is based upon the application of 

emissions factors. The development of emissions factors 

is based upon source testing that incorporates many of the 

underlying uncertainties inherent in the selection of test 

methods. And these are not the only factors contributing to 

the uncertainties in both the development and application 

of emissions factors (for additional information, see the 

introduction to AP-42 (EPA, 1995)).

The uncertainties related to test method selection are 

illustrated in a recent advanced announcement of an update 

of the PM emissions factors for natural gas combustion. 

EPA has announced that it will revise the estimates of 

PM2.5 emissions from natural gas combustion in the fi nal 

version of the 2002 National Emissions Inventory (NEI). 

The revision will decrease the estimated emissions of 

PM2.5 by roughly 95 percent. The Electric Power Research 

Institute (EPRI) also plans to investigate the available test 

methods and may suggest some alternative test methods 

(EPRI, 2005).

It is not yet clear how new test results will affect the overall 

inventory. Sources for which emissions estimates for 

condensable PM are not available or are under-estimated 

may fi nd that the new inventory fi gures are signifi cantly 

higher than previous inventory numbers. Other sources, 

in particular those that have based their estimates on Test 

Method 202 data (excluding nitrogen purging), may fi nd 

that their inventory numbers are somewhat lower than 

under the current inventory (EPA, 2005b).

Lastly, as we have discussed in the Introduction, the 

distinction between fi lterable and condensable PM is not 

just an inventory concern; it also raises regulatory and 

permitting issues.

PM2.5 Source Apportionment

As indicated above, emissions of PM2.5 and PM2.5-

precursors come from a variety of sources and vary by 

location and time. This section discusses several studies 

that have examined the composition of PM2.5 in different 

geographic areas. 

The importance of determining source apportionment 

for ambient PM2.5 in a specifi c area cannot be overstated; 

developing a cost-effective approach to controlling PM2.5

emissions sources requires an understanding of the relative 

contribution from local and regional sources. Adequate 

monitoring data are needed to provide insight into the 

composition of ambient PM2.5 in a given area. 

EPA began an effort to deploy over 1,000 PM2.5 monitors 

nationally in 1997. A handful of computer models are 

available to determine the source apportionment of PM2.5

mass in air samples, including the UNMIX and Positive 

Matrix Factorization (PMF) models. The UNMIX 

model apportions the PM chemical mass to specifi c 

source categories based on an assessment of periods 

when individual sources do not contribute signifi cantly 

to the total mass of any species being modeled. The PMF 

model apportions the PM chemical mass to specifi c source 

categories using a least squares modeling technique.

Source apportionment studies have been performed in 

Phoenix, Denver and various other cities. In Phoenix, 

the aerosol chemical composition of PM2.5 was analyzed 

using the PMF method (Ramadan, 2000). The results 

suggest that motor vehicles, vegetation burning and coalfi red power plants are dominant contributors to the city’s 

PM2.5 mass. The highest concentrations occurred in 

the winter and thus corresponded with the peak tourist 

season and peak fi replace use. A separate study of PM2.5

concentrations in Phoenix, using the UNMIX model, 

arrived at similar results using the same data set (Lewis, 
28 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

2003). The study found that gasoline engines were the 

largest overall contributor (33 percent), and that their 

contribution was higher during the winter months (42 

percent). During the summer, the contribution from 

gasoline engines diminished to 20 percent and was 

surpassed by the contribution from secondary sulfates (29 

percent) and crustal/soil (26 percent). 

The different methodologies used in these studies resulted 

in different conclusions as to the relative contribution 

of gasoline versus diesel engines: the UNMIX method 

estimated a higher contribution of diesel in the total 

vehicle contribution. Other studies have detected similar 

discrepancies in the contribution assigned to gasoline 

and diesel use. It will be important to resolve these 

discrepancies in order to ensure greater confi dence in the 

emissions inventories and source apportionment studies 

used to tailor control strategies.

In Denver, a tracer method was used to estimate source 

contributions to fi ne aerosol concentrations during the 

winter months, when air quality in Denver is the worst 

(Lewis, 1986). This study identifi ed motor vehicles (42 

percent), electric power generation (23 percent) and wood 

burning (12 percent) as the most signifi cant contributors to 

the local PM2.5 mix. A more recent study conducted by the 

Desert Research Institute and Colorado State University 

evaluated monitoring data and also found that most of the 

PM2.5 in the area came from gasoline vehicles and engines 

(Lawson, 1998). Specifi cally, the study found that gasoline 

vehicles and engines were the largest contributor to PM2.5

mass during winter haze episodes (28 percent), followed by 

dust and debris (16 percent), diesel vehicles and engines (10 

percent), wood smoke (5 percent), meat cooking (4 percent), 

and directly emitted PM2.5 from coal-fi red power plants (2 

percent). Particulate ammonium nitrate and particulate 

ammonium sulfate, both formed in the atmosphere from 

a variety of sources, together contributed 35 percent of 

ambient PM2.5.

Numerous other source apportionment studies have 

been conducted across the U.S. For a discussion of the 

available literature and various source apportionment 

methodologies, see EPA’s 2003 report entitled Compilation 

of Existing Studies on Source Apportionment for PM2.5

(EPA, 2003).

References

Comis, Don. “A Bum Rap for Agriculture?” Agricultural 

Research, May 2004.

Electric Power Research Institute (EPRI). 

Evaluation of Stack Sampling Methods for Fine 

Particulates, October 2005. http://www.epriweb.com/

public/000000000001012949.pdf.

Lawson, Douglas, R., and R. Smith, Colorado State 

University. Northern Front Range Air Quality Study: A 

Report to the Governor and General Assembly, December 

1998.

Lewis, Charles, R.H. Baumgardner, R.K. Stevens, and 

G.M. Russwurm. “Receptor Modeling Study of Denver 

Winter Haze,” Environmental Science & Technology

20(11): 1126-1136, 1986.

Lewis, Charles, G. Norris, T. Connor, and R. Henry. 

“Source Apportionment of Phoenix PM2.5 Aerosol with 

the Unmix Receptor Model,” Journal of the Air and Waste 

Management Association, 53(3): 325-38, March 2003.

Ramadan, Z., X.H. Song, and P.K. Hopke. “Identifi cation 

of Sources of Phoenix Aerosol by Positive Matrix 

Factorization,” Journal of the Air and Waste Management 

Association 50: 1308-1320, 2000.

Sardar, S.B., P.M. Fine, and C. Sioutas. “Seasonal and 

Spatial Variability of the Size-Resolved Chemical 

Composition of Particulate Matter (PM10) in the Los 

Angeles Basin,” Journal of Geophysical Research, 110, 

2005.

Winer, Arthur M., R.P. Turco, and W.C. Hinds, UCLA 

Institute of the Environment. Southern California 

Environmental Report Card 2001, 2002. http://www.

earthscape.org/r1/ES14560/wia01.html.

U.S. Environmental Protection Agency (EPA). 

“Introduction,” AP-42, Fifth Edition, Volume I, 1995. 

www.epa.gov/ttn/chief/ap42/c00s00.pdf.

U.S. Environmental Protection Agency (EPA). Compilation 

of Existing Studies on Source Apportionment for PM2.5, 

August 22, 2003. www.epa.gov/oar/oaqps/pm25/docs/

compsareports.pdf.

U.S. Environmental Protection Agency (EPA). The 

Particle Pollution Report: Current Understanding of Air 

Quality and Emissions through 2003 (EPA 454-R-04-002), 

December 2004.

U.S. Environmental Protection Agency (EPA). Review 

of the National Ambient Air Quality Standards for 

Particulate Matter: Policy Assessment of Scientifi c and 

Technical Information, OAQPS Staff Paper (EPA-452/R05-005), June 2005. (2005a)

U.S. Environmental Protection Agency (EPA). Proposed 

Rule to Implement the Fine Particle National Ambient Air 

Quality Standards, September 8, 2005, http://www.epa.

gov/pmdesignations/documents/Sep05/PM25_impl_rule_

and_preamble_090805.pdf. (2005b)
 Chapter 3 - Fine Particulate Matter and Precursor Emissions 29

U.S. Environmental Protection Agency (EPA). Evaluation 

of Potential PM2.5 Reductions by Improving Performance 

of Control Devices: PM2.5 Emission Estimates, Final 

Report, prepared by E. H. Pechan & Associates, Inc.; and 

RTI International, September 27, 2005. (2005c)

U.S. Environmental Protection Agency (EPA). Map of 

Nonattainment Areas, April 2005, http://www.epa.gov/

pmdesignations/documents/Apr05/greenmap.htm. (2005d)

U.S. Environmental Protection Agency (EPA). 2002 

National Emissions Inventory: Mobile Source Draft, June 

2005. www.epa.gov/ttn/chief/net/2002inventory.html. 

(2005e)

U.S. Environmental Protection Agency (EPA). 1999 

National Emissions Inventory Final Version 3.0, obtained 

from EPA staff, October 2005. www.epa.gov/ttn/chief/net/

1999inventory.html. (2005f)

Western Regional Air Partnership (WRAP). Final Report: 

Analysis of the Fine Fraction of Particulate Matter in 

Fugitive Dust, October 12, 2005. http://www.wrapair.org/

forums/dejf/documents/fffd/Final_Fine_Fraction_Dust_

Report.pdf.
30 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 3.1 National Emissions by Source Category (thousand tons)

Source Category PM2.5 SO2 NOx Source

Industrial Boilers

 Pulp and Paper Sector 40 341 210 1999 NEI

 Petroleum Refi neries 9 103 70 1999 NEI

 Iron and Steel Sector 4 32 33 1999 NEI

 Other Sector 97 689 478 1999 NEI

Commercial Boilers 16 111 73 1999 NEI

Total 166 1,276 863

Electric Generating Units

 Coal 535 9,738 4,097 2002 NEI

 Oil 13 343 130 2002 NEI

 Gas 11 8 270 2002 NEI

 Other 8 191 50 2002 NEI

 Internal Combustion 14 13 152 2002 NEI

Total 582 10,293 4,700

Industrial Point Source

 Pulp and Paper Sector (except boilers) 59 109 92 1999 NEI

 Cement 23 184 234 1999 NEI

 Iron and Steel (except boilers) 41 58 65 1999 NEI

 Petroleum Refi neries (except boilers) 27 314 173 1999 NEI

Total 150 665 564

Onroad Vehicles

 Light-Duty Gasoline 45 163 3,797 2002 NEI

 Light-Duty Diesel 2 1 21 2002 NEI

 Motorcyclesa 0.3 0.3 19 2002 NEI

 Heavy-Duty Gasolinea 7 13 497 2002 NEI

 Heavy-Duty Diesel 95 81 3,832 2002 NEI

Total 149 259 8,167

Nonroad Equipment

 Agricultural Diesel 60 54 568 2002 NEI

 Construction and Mining Diesel 60 84 816 2002 NEI

 Industrial Diesel 10 15 133 2002 NEI

 Commercial Diesel 8 8 77 2002 NEI

 Logging Diesel 1 3 24 2002 NEI

 Rail Diesel 23 56 1,075 2002 NEI

 Other nonroadb 37 11 469 2002 NEI

Total 199 231 3,161

Airports

 Aircraft 14 8 86 2002 NEI

 Ground Service Equipment 0.9 1 20 2002 NEI

Total 15 9 106

Continued
 Chapter 3 - Fine Particulate Matter and Precursor Emissions 31

Table 3.1 National Emissions by Source Category (thousand tons)

Source Category PM2.5 SO2 NOx Source

Marine Ports

 Marine Ships Diesel 40 201 1,070 2002 NEI

 Marine Ships Other 33 2 49 2002 NEI

Total 74 203 1,120

Residential

 Natural Gas 24 2 259 1999 NEI

 Oil 6 125 53 1999 NEI

 Wood 419 6 45 1999 NEI

 Coal 5 52 7 1999 NEI

 Open Burning 175 5 33 1999 NEI

Total 630 189 398

Fugitive Dust

 Paved Roads 688 0 0 1999 NEI

 Unpaved Roads 1,304 0 0 1999 NEI

 Agricultural Crops 862 0 0 1999 NEI

 Agricultural Livestock 88 0 0 1999 NEI

 Construction 385 0 0 1999 NEI

Total 3,326 0 0

Other

 Agricultural Burning 152 0.012 11 1999 NEI

 Commercial Cooking 79 0 0 2002 NEI

Total 231 0.012 11

TOTAL 5,522 13,126 19,090

a. Motorcycles and heavy-duty gasoline trucks are not a focus of this report.

b. Other nonroad equipment, including lawn and garden equipment, recreational vehicles, and non-diesel agricultural, 

commercial, industrial, construction, logging and mining equipment, are not a focus of this report.

Source: EPA, 2005e (2002 NEI), 2005f (1999 NEI)
32 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Every chapter of this report that addresses specifi c source 

categories should be read through the lens of the Clean 

Air Act. For example, where EPA is required by the Act 

to establish regulations, state and local agencies are not 

permitted to set standards less stringent than those imposed 

by EPA; in addition, the Act places some restrictions on 

the regulation by states of certain mobile sources. Thus, 

it will be important for state and local regulators, in 

assessing what degree of regulatory freedom they have 

to address emissions from various sources, to understand 

how the Clean Air Act affects the specifi c source category 

or facility under consideration. We provide more detail 

in individual chapters of this report on applicable federal 

statutes as they pertain to specifi c source categories—this 

chapter is intended as an overview.

The federal Clean Air Act is a long and complicated piece 

of legislation. It is easier to understand if broken into 

segments, although there are a number of different ways it 

can be sliced.

One way to understand the Clean Air Act is to examine 

the distinctions it makes among broad source categories. 

The Act treats “stationary” sources (large, non-moving 

producers of pollution such as refi neries and power plants) 

and “mobile” sources (such as cars, trucks and buses) 

differently. In addition, it covers “area” sources: facilities 

that individually are too small to qualify as stationary 

sources, but that are signifi cant polluters in the aggregate 

(e.g., fugitive dust, residential wood stoves).

The Clean Air Act also deals differently with different 

types of pollutants. So-called “criteria” pollutants—

such as ground-level ozone, which is regulated mainly 

by controlling emissions of nitrogen oxides (NOx) and 

volatile organic compounds (VOCs); nitrogen dioxide; 

carbon monoxide (CO); particulate matter (PM); sulfur 

dioxide (SO2); and lead—are regulated separately from 

“hazardous” air pollutants or HAPs (also known as “air 

toxics”), such as arsenic, mercury, and a host of others. 

Furthermore, the Act divides responsibility for various 

types of sources and air pollutants between the states and 

localities on the one hand, and the federal government 

on the other. Generally, the states and EPA share 

responsibility for regulating criteria pollutants from 

stationary and area sources, but states and localities have 

the lead role in addressing emissions from these source 

categories. Section 116 of the Act gives states and local 

agencies the freedom to adopt more stringent standards 

for criteria pollutant emissions from stationary and area 

sources than the Clean Air Act requires. As discussed 

in the Introduction to this report, however, the reality 

is somewhat different. According to a STAPPA and 

ALAPCO survey, 26 states are completely or partially 

precluded by state law or policy from adopting standards 

that are more stringent than federal law requires and a 

number of other states report that they face obstacles in 

Chapter 4

The Clean Air Act
 Chapter 4 - The Clean Air Act 33

implementing more stringent programs. However, 46 

states report that they can adopt requirements if no federal 

programs or standards exist (STAPPA and ALAPCO, 

2002).

The federal government bears most of the burden of 

regulating air toxics and mobile sources, although 

the regulation of mobile sources involves a uniquely 

pragmatic division of responsibility. The Clean Air Act 

allows California to set new vehicle emissions standards 

that are stricter than federal standards. This is because 

California has historically had more severe vehiclerelated air pollution problems than the rest of the country 

and because it already had a history of regulating mobile 

sources at the time the relevant provisions of the Clean Air 

Act were enacted. Other states can adopt the California 

standards (as some have done) for new vehicles, instead 

of following the federal standards. This ensures that auto 

manufacturers will have to meet at most two standards for 

a particular class of vehicles. States are not preempted 

from imposing their own standards on existing onroad

vehicles. We discuss these issues at greater length in the 

section of this chapter on mobile sources.

The National Ambient Air Quality 

Standards 

Under §108 of the Clean Air Act, EPA must set National 

Ambient Air Quality Standards, or NAAQS, for air 

pollutants that in the Agency’s judgment pose serious 

problems for public health or welfare. For these 

pollutants, the Act directs EPA to set “primary” standards 

to protect public health with an adequate margin of 

safety (§109(b)(1)), and “secondary” standards to protect 

public welfare with respect to issues such as visibility 

and materials damage (§109(b)(2)). Table 4.1 shows the 

NAAQS for all the criteria pollutants. The Clean Air 

Act requires that these ambient air quality standards be 

set without regard to the cost of compliance (American 

Trucking Associations, Inc. v. Whitman, 2001) or the 

feasibility of controlling relevant emissions.

Table 4.1

National Ambient Air Quality Standards

Pollutant Primary Standards Averaging Times Secondary Standards

Carbon Monoxide 9 ppm (10 mg/m3

) 8-hour none

35 ppm (40 mg/m3

) 1-hour none

Lead 1.5 μg/m3 quarterly average same as primary

Nitrogen Dioxide 0.053 ppm (100 μg/m3

) annual (arithmetic mean) same as primary

Particulate Matter (PM10) 50 μg/m3 annuala

 (arithmetic mean) same as primary

150 μg/m3 24-hourb

Particulate Matter (PM2.5) 15.0 μg/m3 annualc (arithmetic mean) same as primary

65 μg/m3 24-hourd

Ozone 0.08 ppm 8-houre same as primary

Sulfur Oxides 0.03 ppm annual (arithmetic mean) NA

0.14 ppm 24-hourb NA

NA 3-hourb 0.5 ppm (1300 μg/m3

)

a. To attain this standard, the 3-year average of the weighted annual mean PM10 concentrations at each monitor within an area must not 

exceed 50 μg/m3.

b. Not to be exceeded more than once per year. 

c. To attain this standard, the 3-year average of the weighted annual mean PM2.5 concentrations from single or multiple communityoriented monitors must not exceed 15.0 μg/m3

.

d. To attain this standard, the 3-year average of the 98th percentile of 24-hour concentrations at each population-oriented monitor within 

an area must not exceed 65 μg/m3.

e. To attain this standard, the 3-year average of the fourth-highest daily maximum 8-hour average ozone concentrations measured at 

each monitor within an area over each year must not exceed 0.08 ppm. 

Source: EPA, 2005f
34 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Geographic areas within states are classifi ed in terms of 

where they stand in achieving the NAAQS for each criteria 

pollutant. Areas are designated as “nonattainment” (they 

fail to meet the standards), “attainment” (they meet the 

standards), or “unclassifi able” (not enough information 

to tell). The classifi cation scheme has additional levels 

of complexity. For example, under §188 of the Act, areas 

that are in nonattainment for PM10 are classifi ed as either 

moderate or serious. As the nonattainment classifi cation 

goes from moderate to serious, more stringent pollution 

control requirements apply, but state and local authorities 

are given more time to demonstrate attainment. 

EPA promulgated the NAAQS for PM2.5 in 1997. In 

April 2005, the Agency fi nalized its determination that 

208 counties comprising 39 metropolitan areas (now 36, 

based on reclassifi cations) were in nonattainment of the 

standard. Most of these nonattainment areas are east of 

the Mississippi River; however, three are in the West—two 

in California and one in Libby, Montana. The deadline for 

attaining the PM2.5 NAAQS is April 2010, but states must 

submit State Implementation Plans (SIPs) by April 2008. 

Under §172(a)(2) of the Clean Air Act, EPA can grant a 

fi ve-year extension for areas with more severe problems. 

Meanwhile, the PM2.5 NAAQS are again undergoing 

the periodic Agency review that is required at fi ve-year 

intervals under §109(d)(1) of the Clean Air Act. Under 

the terms of a consent decree, EPA issued its proposed 

PM2.5 standards (as well as proposed standards for larger 

particulates) on January 17, 2006, and must issue fi nal 

standard by September 27, 2006.

EPA estimates that meeting the current PM2.5 standards 

would avoid tens of thousands of premature deaths 

annually and save hundreds of thousands more people 

from signifi cant respiratory or cardiovascular disease. 

EPA further estimates that—depending on the particular 

emissions controls required for sources of PM2.5-

precursor emissions and depending on the locations of 

those sources—the monetized health benefi ts of reducing 

pollutant emissions that lead to PM2.5 formation exceed the 

costs by three to more than 30 times (EPA, 2005d).

State Implementation Plans 

Section 110 of the Clean Air Act requires states to write 

SIPs indicating how they will achieve the NAAQS for each 

pollutant. States have the lead in controlling air pollution, 

with EPA stepping in only if a state fails to submit a SIP, 

submit an adequate SIP, or to implement the SIP. Both the 

NAAQS and the SIPs are applicable to stationary, area and 

mobile sources. The stringency of the air pollution controls 

that states have to impose in their Plans depends on 

whether the area in question is classifi ed as nonattainment 

or attainment and—in the case of nonattainment areas—

on the degree of nonattainment. 

SIPs must also contain provisions for limiting “transport,” 

meaning that states must prohibit the sources within their 

jurisdiction from sending so much air pollution downwind 

that areas in other states are unable to meet or maintain 

federal air quality standards (§110(a)(2)(D)).

SIPs are adopted as state regulations and, once approved by 

EPA, become enforceable as federal regulations. However, 

§179 of the Act provides that if a state fails to submit a 

SIP, or submits a SIP that is insuffi cient, EPA can impose 

sanctions (such as a loss of federal highway subsidies), or 

write its own plan for the area in question (known as a 

Federal Implementation Plan, or FIP). 

Stationary and Area Sources

As discussed above, the Clean Air Act addresses criteria 

pollutants through the NAAQS, which are implemented 

by the federal government and by state and local agencies 

through a complicated scheme of shared authority in which 

the states take the lead. However, several other parts of 

the Act govern emissions of both criteria pollutants and air 

toxics, adding layers of requirements to the core NAAQS 

requirements.

Hazardous Air Pollutants or Air Toxics

Section 112 of the Clean Air Act regulates HAPs, or air 

toxics, differently from criteria pollutants. The Act 

specifi es 188 HAPs—chemicals that are known to cause, 

or are suspected of causing, adverse human health or 

environmental effects. It directs EPA to identify the 

categories of sources that emit these pollutants and then 

to develop technology-based national emissions standards, 

applicable both to new and existing sources, for each of 

the categories.1 These Maximum Achievable Control 

Technology (MACT) standards apply to sources with 

potential emissions of 10 tons per year of a single HAP or 

25 tons per year of combined HAPs.

Section 112(d) requires that MACT standards be based 

on the maximum reduction of emissions possible through 

the application of control technologies or work practices. 

The so-called “MACT fl oor,” or baseline level at which 

EPA sets the MACT standards for a source category, is 

determined without regard to the cost of compliance. The 

MACT fl oor for existing sources may not be less stringent 

than “the average emission limitation achieved by the 

best performing 12 percent of the existing sources.” The 

MACT fl oor for new sources may not be “less stringent 

than the emissions control that is achieved in practice by 

the best controlled similar source.” EPA can set standards 

that are even more stringent than the fl oor, but if it does 

1. For the purposes of §112, “new” sources include those that have been 

“reconstructed” (i.e., where the cost of reconstruction exceeds 50 percent of the cost of constructing a new source); “existing” sources include 

those that have been “modifi ed” (EPA, 2004).
 Chapter 4 - The Clean Air Act 35

so it must take costs into account. Although MACT rules 

address air toxics, in some instances the rules achieve 

reductions in PM emissions as a co-benefi t. In some 

MACT rules, for example, EPA regulates PM (but not the 

fi ne fraction separately) as a surrogate for the regulation of 

metals.

Section 112(f) of the Act requires that eight years after 

promulgating technology-based MACT standards for a 

source category, EPA must evaluate the “residual” risk, if 

any, that remains and promulgate regulations to address 

that risk.

Note that the MACT regulations (as opposed to the 

later assessment of residual risk that is supposed to 

follow) refl ect an entirely different approach from 

that embodied in the NAAQS approach to criteria air 

pollutants. The NAAQS for criteria pollutants are based 

on a determination about the level of air quality needed to 

protect public health and the environment, rather than on 

the technologies or work practices that are available for 

reducing emissions.

Additional Regulatory Programs

Previous sections of this chapter suggest two ways 

to understand the Clean Air Act: fi rst, through its 

classifi cation of emissions sources into stationary, area 

and mobile source categories and second, with reference 

to the different treatment of criteria pollutants and HAPs. 

Another way to understand the Act is by reviewing some 

of the most signifi cant additional regulatory programs it 

creates for controlling emissions from stationary and area 

sources.

RACM/RACT/BACM. Section 172(c)(1) of the Clean 

Air Act requires nonattainment SIPs to provide for the 

implementation of all Reasonably Available Control 

Measures (RACM), which include Reasonably Available 

Control Technology (RACT). These requirements are 

applicable to both new and existing sources, although—

as a practical matter—other, much more stringent 

requirements dictate the standards for new sources. 

Although not specifi cally defi ned by the Clean Air 

Act, EPA has defi ned RACT as the lowest emissions 

limitation that a source can meet using control technology 

that is reasonably available, taking into consideration 

technological and economic feasibility (EPA, 2005d). 

For “serious” PM10 nonattainment areas, §189(b) of the 

Clean Air Act requires BACM, or best available control 

measures. 

Federal law does not establish actual RACM, RACT 

or BACM limits—it only provides guidelines pursuant 

to which the states adopt regulations. Most of these 

guidelines are known as Control Technique Guidelines 

(CTGs, pursuant to §108(b) of the Act) and most address 

emissions of VOCs. EPA has not issued any new sectorspecifi c CTGs in 25 years. For NOx, the federal guidelines 

are referred to as Alternative Control Techniques (ACTs, 

pursuant to §183(c)). The ACT guidelines describe the 

control technologies that are available to address NOx

emissions, but do not actually specify the emissions limits 

that EPA considers to constitute RACT. There are no 

CTGs for NOx, and no sector-specifi c CTGs for SO2, PM10

or PM2.5.

RACT limits are signifi cant because they apply not just to 

new, but also to existing sources. However, many ACTs 

were promulgated a decade or more ago and they have been 

eclipsed by subsequent technology developments. Also, 

as was already noted, they are only intended to provide 

guidance, on which—as EPA acknowledges—signifi cant 

variation may be appropriate. Like New Source Review 

(NSR) standards, RACT standards—which are informed 

by the ACTs—represent moving targets that are intended 

to refl ect advancements in technology.

NSR/PSD. NSR is the Clean Air Act preconstruction 

permitting program that applies to major stationary sources 

of air pollution when they are fi rst built or signifi cantly 

modifi ed. NSR requires—among other things—that 

sources install updated environmental controls. The term 

“NSR” is often used to refer to two distinct programs: 

nonattainment NSR, which operates in areas that are in 

nonattainment with one or more of the NAAQS (Secs. 171–

193), and the Prevention of Signifi cant Deterioration (PSD) 

program, which operates in attainment and unclassifi able 

areas (Secs.160–169B). 

States also have their own state preconstruction permitting 

programs that may apply to sources or activities other than 

those covered by the federal programs. These programs 

vary widely (Hawkins, 2004).

NSR requires new and modifi ed plants located in 

attainment areas to implement Best Available Control 

Technology (BACT); in nonattainment areas, the standard 

is the Lowest Achievable Emission Rate or LAER (Secs. 

165(a)(4) and 173(a)(2), respectively). The key difference 

between BACT and LAER standards is that BACT takes 

cost into account while LAER does not (Hawkins, 2004). 

Unlike New Source Performance Standards (discussed 

below) and MACT standards for HAPs, BACT and LAER 

standards are not codifi ed. Instead, they are moving 

targets, intended to refl ect technology advancements as 

they occur. Current RACT, BACT and LAER guidelines 

are theoretically listed in EPA’s RACT/BACT/LAER 

Clearinghouse which, unfortunately, is not kept reliably 

up-to-date.

New plants in nonattainment areas are subject to a 

number of other important requirements, including—for 
36 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

ozone—the requirement that new plants provide emissions 

reductions that would not otherwise be mandated to 

“offset” any additional air pollution they cause (§173). 

Offsets are meant to guarantee that the construction of a 

new source does not increase total pollution emissions in 

the area where the source is located. The required offset 

ratio is dependent upon the degree of nonattainment of the 

area. 

NSPS. Unlike NSR, the New Source Performance 

Standards (NSPS) provided for under §111 of the Clean 

Air Act apply without regard to an area’s attainment 

status. Like MACT standards, but unlike NSR and RACT 

standards, the NSPS are codifi ed and do not refl ect realtime technology improvements. Although it is relatively 

unusual, in some circumstances the NSPS apply to existing

sources. In these instances, §111(d) of the Act requires 

EPA to establish “emissions guidelines” rather than 

regulatory limits. 

More typically, however, the NSPS apply to new and 

reconstructed, rather than existing, sources.2 As with the 

MACT standards, reconstruction is defi ned as replacing 

components such that the cost exceeds 50 percent of the 

cost of constructing a new source (EPA, 1975).

Under §111, EPA must develop a list of source categories 

subject to the NSPS. The standards themselves are 

technology based and are required to refl ect “the best 

system of emissions reduction which...the Administrator 

determines has been adequately demonstrated.” In 

establishing the NSPS, EPA is required to take cost into 

consideration.

NSPS requirements are usually less stringent than the 

standards imposed pursuant to NSR because the NSPS are 

fi xed standards, whereas NSR requirements are decided 

on a case-by-case basis and are intended to refl ect recent 

technology developments. Also, in nonattainment areas 

a modifi cation is more likely to trigger NSR because the 

trigger for NSPS requirements involves an increase in the 

emissions rate, while EPA has historically argued that only 

an increase in total tons of pollution is required to trigger 

NSR. Note, however, that EPA has proposed to eliminate 

this distinction may be eliminated by virtue of rule 

changes to the NSR program that the Agency proposed in 

October 2005 (EPA, 2005e).

Regional Haze/BART. Regional haze refers to the 

visibility impairment caused by emissions of PM2.5 and 

2. NSPS technically also apply to modifi cations, which are treated as 

new sources under this program (unlike §112 MACT standards, which 

treat modifi ed sources as existing sources). However, for complicated 

reasons having partly to do with EPA’s use of certain Internal Revenue 

Service defi nitions, most modifi cations do not trigger the NSPS. Under 

the NSPS test, a modifi cation occurs if certain kinds of changes increase 

the hourly emissions rate of a pollutant (EPA, 2000a).

PM2.5-precursors from numerous sources located in a wide 

geographic area. Section 169A(b)(2) of the Clean Air Act 

requires certain existing stationary sources in attainment 

and nonattainment areas to install Best Available Retrofi t 

Technology (BART), where BART is defi ned as “an 

emission limitation based on the degree of reduction 

achievable through the application of the best system of 

continuous emission reduction for each pollutant emitted” 

(EPA, 2005a). BART applies to large sources in 26 

identifi ed source categories that began operation between 

1962 and 1997 (§169A(g)(7)).

Section 169A of the Clean Air Act establishes a national 

visibility goal that calls for “the prevention of any future, 

and the remedying of any existing, impairment of visibility 

in Class I areas, which impairment results from manmade 

air pollution.” The term “Class I area” refers to 156 areas: 

national parks exceeding 6000 acres, wilderness areas 

and national memorial parks exceeding 5000 acres, and 

international parks in existence on August 7, 1977. 

Pursuant to §169B of the Act, EPA fi nalized revisions to its 

original 1980 haze regulations in July 1999 (EPA, 1999). 

Unlike the 1980 rulemaking that applied to 35 states, the 

1999 rule extends coverage to all states, requiring them 

to establish goals and emissions reduction strategies for 

improving visibility in the nation’s 156 Class I areas. 

The regional haze rule requires states to develop 

implementation plans that: 

ensure reasonable progress toward the national goal 

of eliminating manmade visibility impairment by 

2064; 

contain provisions for BART; and 

specify a long-term strategy for achieving the 

national goal. 

The initial implementation period for the rule extends 

to the year 2018, with a reassessment and revision of 

emissions reduction strategies, as appropriate, every ten 

years thereafter. State strategies must address all types of 

sources (stationary, mobile and area) and activities that 

degrade visibility in downwind Class I areas, regardless of 

whether the affected Class I areas are located within the 

state’s own boundaries.

After protracted litigation that included the D.C. Circuit 

Court of Appeals’ vacatur of substantial portions of the 

regional haze rule (American Corn Growers Association v. 

EPA, 2002), EPA fi nalized amendments to the rule on July 

6, 2005 (EPA, 2005a). The amendments include so-called 

“BART guidelines” for states to use in identifying sources 

subject to BART and applicable controls, as well as general 

provisions that address the use of trading programs as a 

substitute for BART. States have not yet developed their 

•

•

•
 Chapter 4 - The Clean Air Act 37

own BART regulations. 

EPA also proposed revisions to the regional haze rule on 

August 1, 2005 (EPA, 2005b). These revisions contain 

more detailed provisions for the use of trading programs as 

a substitute for BART; they also propose special provisions 

for a group of western states and tribes.

States are currently required to develop their regional haze 

SIPs by December 2007.

The Acid Rain Program. The Acid Rain Program 

established by Title IV of the Clean Air Act imposes an 

additional layer of regulation on electric generating units 

(EGUs), or power plants, only. The program requires the 

reduction of NOx and SO2 emissions. Title IV imposes a 

national “cap-and-trade” program—the fi rst of its kind—

for EGU emissions of SO2, but not for NOx.

A cap-and-trade program sets a cap on total emissions of a 

particular pollutant from the regulated industry sector and 

creates authorizations (“allowances”) to emit a specifi ed 

quantity of that pollutant. Allowances are then allocated to 

sources in the sector, with the total number of allowances 

equaling the level of the cap. Sources surrender allowances 

equal to their emissions (e.g., one allowance for each 

ton of pollutant emitted). This approach gives sources 

considerable compliance fl exibility: they can choose to 

implement controls or purchase allowances from sources 

with lower marginal abatement costs. Notwithstanding 

these provisions, the Clean Air Act prohibits a source from 

emitting at levels that would violate the applicable SIP, 

regardless of the number of SO2 allowances it holds under 

the Acid Rain Program.

The Clean Air Interstate Rule. On May 12, 2005, EPA 

fi nalized the Clean Air Interstate Rule (CAIR) to reduce 

interstate transport of pollutants under §110(a)(2)(D) 

of the Clean Air Act (EPA, 2005c). The Agency found 

that a total of 28 states and the District of Columbia 

contribute signifi cantly to nonattainment or interfere 

with maintenance of the NAAQS for PM2.5 and/or ozone 

in downwind states. Like the Acid Rain Program, CAIR 

requires reductions in emissions of the PM2.5-precursors 

NOx and SO2.

CAIR creates three federal cap-and-trade programs: an 

annual program for SO2, an annual program for NOx, and 

a seasonal program for NOx. These programs cover EGUs, 

but states can include in their seasonal NOx program large 

industrial boilers (greater than 250 MMBtu/hr) that are 

included in the NOx SIP Call’s NOx trading program, so 

long as they adhere to the cap established under the SIP 

Call program. These are the only non-EGU sources that 

can be included in any of the CAIR trading programs 

without disqualifying the state from participation in the 

federal trading regimes. 

States have at least four choices for complying with 

CAIR: (1) participate in the three federal cap-and-trade 

regimes, which EPA will run; (2) create a cap-and-trade 

regime within the state for all or some of the pollutants 

and sources of the state’s choice; (3) achieve the required 

reductions through other methods, such as imposing 

controls on EGUs or other sources; or (4) create a hybrid 

of these options.

Figure 4.1 shows the states affected by CAIR.

Although CAIR is currently being litigated, most of the 

petitioners have raised relatively peripheral issues that do 

not threaten the core of the rule.

Operating Permits

Under Title V of the Clean Air Act, individual stationary 

sources implement SIP requirements through operating 

permits issued by the state. Both the state operating 

permit programs and individual operating permits are 

subject to EPA approval. A permit, which lasts for fi ve 

years, sets specifi c emissions limits for the source for 

various pollutants. Permits are intended to collect in one 

document all of the pollution control, operating, emissions, 

monitoring, reporting and certifi cation requirements for a 

facility. Most states have permitting programs for minor 

sources in addition to their Title V permitting programs 

for major sources.

Mobile Sources

Under the Clean Air Act, the federal government sets 

emissions standards for new vehicles. However, as noted 

previously in this chapter, California can set new vehicle 

emissions standards that are stricter than federal standards 

and other states may adopt those standards. States are not 

preempted from setting their own standards for most types 

Fig. 4.1 States Affected by CAIR

ozone & PM

ozone only

PM only

not covered
38 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

of existing vehicles. 

Although this arrangement means that SIP writers have 

fewer opportunities to go beyond federal standards in the 

case of mobile sources (as compared to stationary sources), 

it would be a mistake to conclude that states have no 

options for reducing vehicle emissions. In fact, there are 

countless cases of state and local programs addressed to 

motor vehicle emissions. For example, in 2005 New Jersey 

enacted a mandatory diesel retrofi t program for onroad 

vehicles and New York City adopted legislation mandating 

the retrofi t of various types of trucks and buses. More 

than 20 cities and states have requirements that restrict the 

idling of diesel vehicles and at least ten states have adopted 

or moved to adopt California light-duty vehicle standards. 

EPA reported in 2003 that 33 states and the District of 

Columbia had an inspection and maintenance program 

for light-duty vehicles in at least one city or county. 

According to the Department of Energy, eight states and 

the federal government provided purchase incentives for 

environmentally friendly vehicles in 2005. The mobile 

source chapters of this report (Chapters 12–15) discuss 

state and local strategies, including these, in greater detail. 

This section aims only to provide an overview of the Clean 

Air Act as it applies to mobile sources.

Although EPA regulates emissions from new vehicles 

and vehicle fuels and fuel additives under the Clean Air 

Act, the National Highway Traffi c Safety Administration 

(within the U.S. Department of Transportation) regulates 

vehicle fuel effi ciency by setting corporate average fuel 

economy (CAFE) standards under the Energy Policy and 

Conservation Act of 1975. However, the line between 

vehicle emissions standards and CAFE standards has 

become disputed recently in the context of on-going 

litigation by automakers that challenges California’s 

efforts to reduce greenhouse gas emissions from cars. In 

their lawsuit, the automakers argue that the California 

rules amount to de facto fuel economy standards and are 

therefore preempted by federal law, which puts vehicle 

effi ciency beyond the reach of state regulatory authority.

Motor Vehicles, Nonroad Engines, Aircraft

The Clean Air Act divides mobile sources into three 

categories: on-road motor vehicles, (such as cars, trucks 

and buses); aircraft; and nonroad vehicles and engines 

(which is a large catch-all category for vehicles and 

equipment like lawnmowers, tractors, forklifts, motorboats, 

ships, locomotives, construction equipment, and the like). 

Generally, it is the federal government rather than the 

states that bears the responsibility for regulating emissions 

from new sources in these categories. The principal 

exception to this is the authority granted to California to 

adopt its own more stringent emissions standards for new 

mobile sources. Other states are permitted to adopt these 

California standards and a number have exercised this 

important authority. For example, to date at least ten states 

have adopted or moved to adopt California’s low emissions 

vehicle program; nine states have adopted California’s 

heavy-duty diesel truck standards for model years 2007 

and later; and 13 states have adopted California’s diesel 

truck “not-to-exceed” requirements (STAPPA and 

ALAPCO, 2005). 

For existing onroad motor vehicles, states and localities 

have much more leeway; in fact, they are free to adopt their 

own standards for these vehicles. However, in the case of 

existing nonroad equipment, they are limited to California 

standards (§209(e)). The Clean Air Act also preempts state 

regulation of aircraft (§233), new locomotives, and small 

construction and farm equipment (§209(e)).

Among federal vehicle standards, the so-called “Tier 

2” standards govern exhaust emissions from light-duty 

vehicles, light-duty trucks, and medium-duty passenger 

vehicles (a category that captures some minivans and 

SUVs) (§§202 (a) and (b); EPA, 2000b). Although a 

separate statutory program governs vehicle fuels (§211), 

the Tier 2 program also requires gasoline refi ners to lower 

the sulfur in gasoline because sulfur in fuel interferes with 

emissions control equipment.

EPA has promulgated the so-called “Phase 2” rule (as 

distinct from the Tier 2 rule) to reduce emissions from 

heavy-duty engines and vehicles. Under the Phase 2 rule, 

sulfur levels in diesel fuel will decline by 97 percent 

compared to current levels (EPA, 2000c). Special 

provisions under §219 of the Clean Air Act impose 

more stringent PM standards for urban buses than for 

other heavy-duty engines (EPA, 1993a). Section 219(d) 

establishes an urban bus rebuild/retrofi t program (EPA, 

1993b). Additionally, EPA has promulgated a series of 

rules since 1995 regulating a number of categories of 

nonroad engines.

Apart from provisions governing emissions standards, the 

Act provides authority for a host of other specifi c vehicle 

programs, such as those governing evaporative emissions, 

onboard diagnostics (to determine whether a vehicle’s 

emissions control systems are functioning properly), 

and vehicle fl eets in certain ozone and carbon monoxide 

nonattainment areas. 

Fuels and Fuel Additives

Under §211(c) of the Clean Air Act, EPA has the authority 

to regulate vehicle fuels and fuel additives. As we 

have seen in the context of the Tier 2 and Phase 2 rules 

discussed above, the Agency has increasingly tended 

to treat emissions standards and fuel requirements as a 

single system rather than as separate issues. This is largely 

because of the effect of some fuel components (e.g., lead, 

sulfur) on required pollution control equipment. 
 Chapter 4 - The Clean Air Act 39

Additionally, the Act creates a number of specifi c 

programs for vehicle fuels, including programs to 

control the volatility of gasoline (§211(h)); to address the 

reformulation of gasoline in certain areas (§§211(k) and 

211(c)); and to prohibit the sale of leaded gasoline for use in 

motor vehicles (§211(n)). The recent Energy Policy Act of 

2005 eliminated the requirement that oxygenates be used 

in reformulated fuel to reduce emissions of CO and ozone 

precursors, but it also required that ethanol use for vehicle 

fuel be tripled by 2012. 

As discussed in Chapter 4, The Clean Air Act, if EPA 

has regulated a fuel characteristic or component, states 

other than California may not adopt either their own or 

California’s regulation—they must follow the federal 

regulation. The only exception to this is the situation in 

which the Administrator fi nds that state regulation is 

necessary for achieving the NAAQS. On the other hand, 

California may adopt its own fuel regulations (§211(c)(4)). 

Transportation Measures

In addition to emissions standards for mobile sources 

and provisions for fuels and fuel additives, the Clean Air 

Act includes a variety of transportation-related measures. 

Although many of these provisions are addressed to ozone 

nonattainment areas, they are worthy of consideration for 

PM reduction purposes, since NOx is a precursor not only 

of ozone, but also of PM. The transportation provisions 

in §182 of the Act include inspection and maintenance 

requirements for automobiles as well as transportation 

control measures aimed at reducing vehicle miles traveled, 

congestion, and work-related vehicle trips. 

The conformity provisions of §176(c) of the Clean Air Act 

are not limited to ozone nonattainment areas. Although 

these provisions have been applied most frequently to 

federal transportation projects, §176(c) prohibits federal 

action—including federal fi nancial assistance—for 

any transportation project that does not conform to the 

applicable SIP.

Finally, §209(d) of the Act specifi cally provides that 

“[n]othing...shall preclude or deny to any State or political 

subdivision thereof the right otherwise to control, regulate, 

or restrict the use, operation, or movement of registered 

or licensed motor vehicles.” Therefore, state and local 

programs such as those aimed at limiting idling, reducing 

congestion and encouraging shared transportation are 

clearly permissible.

The Proposed PM2.5 Implementation 

Rule 

On September 8, 2005, EPA issued its proposed PM2.5

implementation rule, which addresses requirements that 

states must meet in developing their SIPs for attaining the 

PM2.5 NAAQS (EPA, 2005d). The proposed rule includes 

the following provisions:

Attainment dates: Attainment demonstrations and SIPs 

are due by April 2008. Attainment dates are fi ve years 

after designation, or April 2010 for most areas. Extensions 

are possible.

Classifi cations: EPA prefers not to have a classifi cation 

system for nonattainment areas but may decide to establish 

a two-tiered system, with areas classifi ed as moderate or 

serious.

PM2.5-precursors: SO2 emissions must always be 

addressed in PM2.5 SIPs. VOCs and ammonia need not be 

addressed unless EPA or the state demonstrates that either 

is a signifi cant contributor to PM2.5 formation in the area. 

NOx must be addressed in the absence of a demonstration 

that it is not a signifi cant contributor. 

RACT: EPA suggests a number of possible approaches to 

RACT. First, it is unlikely that RACT will be required for 

all stationary sources in all nonattainment areas because 

of the Agency’s view that certain areas will attain the 

standards by 2010 solely as a result of existing federal 

emissions reduction programs. With some caveats, 

previous RACT determinations for other programs may be 

acceptable for purposes of PM2.5 RACT.

NSR: The NSR/PSD proposals are extensive. They 

include:

a major source threshold of 100 tons per year;

a signifi cant emissions increase level of ten tons per 

year;

an offset ratio of 1:1, with the possibility of interpollutant trading;

PM10 as a surrogate for PM2.5 until the fi nal rule is 

promulgated.

EPA’s proposed PM2.5 implementation rule also includes a 

special provision for RACT and EGUs. If a state meets 

its CAIR SO2 cap through EGU reductions only, then 

EGUs that are located in nonattainment areas and that 

are complying with CAIR would be found to meet RACT. 

The same would be true with respect to the state’s NOx

cap, but only if EGUs that have installed selective catalytic 

reduction control technology operate this technology year 

round.

References

American Corn Growers Association v. EPA, 291 F.3d 1 

•

•

•

•
40 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

(D.C. Cir. 2002).

American Trucking Associations, Inc. v. Whitman, 531 

U.S. 457 (2001).

Clean Air Act, 42 U.S.C. §§7401, et seq., December 23, 

1995.

Energy Policy Act of 2005, Public Law 109-58, 119 Stat.594 

(2005).

Energy Policy and Conservation Act of 1975, 15 U.S.C. 

§753 (1976).

Hawkins, Bernard F., Jr., and M.E. Ternes. “The New 

Source Review Program: Prevention of Signifi cant 

Deterioration and Nonattainment New Source Review,” 

Chapter 6 in: Martineau, Robert J., Jr., and D.P. Novello, 

eds., American Bar Association, The Clean Air Handbook: 

Second Edition, 2004.

Horowitz, Michael. “Regulation of Mobile Sources: Motor 

Vehicles, Nonroad Engines, and Aircraft,” Chapter 10 in: 

Martineau, Robert J., Jr., and D.P. Novello, eds., American 

Bar Association, The Clean Air Handbook: Second 

Edition, 2004.

Martel, Jonathan S. “Regulation of Fuels and Fuel 

Additives,” Chapter 11 in: Martineau, Robert J., Jr., and 

D.P. Novello, eds., American Bar Association, The Clean 

Air Handbook: Second Edition, 2004.

Martineau, Robert J. Jr., and M.K. Stagg. “New Source 

Performance Standards,” Chapter 9 in: Martineau, Robert 

J., Jr., and D.P. Novello, eds., American Bar Association, 

The Clean Air Handbook: Second Edition, 2004.

State and Territorial Air Pollution Program Administrators 

and the Association of Local Air Pollution Control Offi cials 

(STAPPA and ALAPCO). Restrictions on the Stringency 

of State and Local Air Quality Programs: Results of a 

Survey by the State and Territorial Air Pollution Program 

Administrators (STAPPA) and the Association of Local 

Air Pollution Control Offi cials (ALAPCO), December 17, 

2002. www.4cleanair.org/stringency-report.pdf.

State and Territorial Air Pollution Program Administrators 

and the Association of Local Air Pollution Control 

Offi cials (STAPPA and ALAPCO). NTE Model Rule, 

accessed December 20, 2005, from: www.4cleanair.org/

InnovationDetails.asp?innoid=2.

U.S. Environmental Protection Agency (EPA). 

“Standards of Performance for New Stationary Sources; 

Reconstruction,” 40 CFR §60.15, December 16, 1975.

U.S. Environmental Protection Agency (EPA). “Control of 

Air Pollution From New Motor Vehicles and New Motor 

Vehicle Engines; Particulate Emission Regulations for 1993 

Model Year Buses, Particulate Emission Regulations for 

1994 and Later Model Year Urban Buses, Test Procedures 

for Urban Buses, and Oxides of Nitrogen Emission 

Regulations for 1998 and Later Model Year Heavy-Duty 

Engines; Final Rule,” Federal Register 58: 15781, March 

24, 1993. (1993a)

U.S. Environmental Protection Agency (EPA). “Retrofi t/

Rebuild Requirements for 1993 and Earlier Model Year 

Urban Buses; Fuel Quality Regulations for Certifi cation 

Diesel Test Fuel; Final Rule,” Federal Register 58: 21359, 

April 21, 1993. (1993b)

U.S. Environmental Protection Agency (EPA). “Regional 

Haze Regulations; Final Rule” Federal Register 64(126): 

35714, July 1, 1999.

U.S. Environmental Protection Agency (EPA). “Standards 

of Performance for New Stationary Sources; Modifi cation” 

40 CFR §60.14(a), Oct. 17, 2000. (2000a)

U.S. Environmental Protection Agency (EPA). “Control 

of Air Pollution from New Motor Vehicles: Tier 2 Motor 

Vehicle Emissions Standards and Gasoline Sulfur Control 

Requirements; Final Rule,” Federal Register 65(28): 6698, 

February 10, 2000. (2000b)

U.S. Environmental Protection Agency (EPA). “Emissions 

Control, Air Pollution From 2004 and Later Model Year 

Heavy-Duty Highway Engines and Vehicles; Light-Duty 

On-Board Diagnostics Requirements, Revision; Final 

Rule,” Federal Register 65(195): 59896, October 6, 2000. 

(2000c)

U.S. Environmental Protection Agency (EPA). “National 

Emission Standards for Hazardous Air Pollutants for 

Source Categories; Defi nitions,” 40 CFR §63.2, Apr. 22, 

2004.

U.S. Environmental Protection Agency (EPA). “Regional 

Haze Regulations and Guidelines for Best Available 

Retrofi t Technology (BART) Determinations; Final Rule” 

Federal Register 70(128): 39104, July 6, 2005. (2005a)

U.S. Environmental Protection Agency (EPA). “Regional 

Haze Regulations; Revisions to Provisions Governing 

Alternative to Source-Specifi c Best Available Retrofi t 

Technology (BART) Determinations; Proposed Rule,” 

Federal Register 70(146): 44154, August 1, 2005. (2005b)

U.S. Environmental Protection Agency (EPA). “Rule To 

Reduce Interstate Transport of Fine Particulate Matter and 

Ozone (Clean Air Interstate Rule); Revisions to Acid Rain 
 Chapter 4 - The Clean Air Act 41

Program; Revisions to the NOX SIP Call; Final Rule,” 

Federal Register 70(91): 25161, May 12, 2005. (2005c)

U.S. Environmental Protection Agency (EPA). “Proposed 

Rule to Implement the Fine Particle National Ambient 

Air Quality Standards; Proposed Rule,” Federal Register

70(210): 66106, November 1, 2005. www.epa.gov/fedrgstr/

EPA-AIR/2005/November/Day-01/a20455.pdf. (2005d)

U.S. Environmental Protection Agency (EPA). “Prevention 

of Signifi cant Deterioration, Nonattainment New Source 

Review, and New Source Performance Standards: 

Emissions Test for Electric Generating Units; Proposed 

Rule,” Federal Register 70(202): 61081, October 20, 2005. 

www.epa.gov/fedrgstr/EPA-AIR/2005/October/Day-20/

a20983.htm. (2005e)

U.S. Environmental Protection Agency (EPA). National 

Ambient Air Quality Standards, accessed September 15, 

2005, from: www.epa.gov/air/criteria.html. (2005f)

Wyman, Robert A., Jr., D.M. Kato, and J.S. Alexander. 

“Meeting Ambient Air Standards: Development of the 

State Implementation Plans,” Chapter 3 in: Martineau, 

Robert J., Jr., and D.P. Novello, eds., American Bar 

Association, The Clean Air Handbook: Second Edition,

2004.

Zbur, Rick, H. Boo, and T.S. Lee. “Transportation and 

Conformity Requirements in State Implementation Plans,” 

Chapter 4 in: Martineau, Robert J., Jr., and D.P. Novello, 

eds., American Bar Association, The Clean Air Handbook: 

Second Edition, 2004.
42 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Boilers account for a large share of the fuel consumed by 

American industry. In 2003, the electric power sector 

alone consumed more than 23,000 trillion British thermal 

units (TBtu) of fuel for steam production (EIA, 2004). 

Apart from the electric industry, the most steam-intensive 

industries are forest products (1,381 TBtu), chemical 

manufacturing (1,055 TBtu), and petroleum refi ning (680 

TBtu) (EERE, 2004). A substantial share of the overall 

fuel consumed by these industries is used for steam 

production; steam boilers account for 84 percent of the 

total energy used in the pulp and paper industry, 47 percent 

of the energy used in the chemical manufacturing industry, 

and 51 percent of the energy used in the petroleum refi ning 

industry (DOE, 2002).

In short, a boiler is a closed vessel or tank in which heat 

produced from the combustion of fuels such as natural 

gas, fuel oil, or coal is used to generate hot water or 

steam. The steam produced in boilers is used for a range 

of applications, including process heating, electricity 

production, and facility heating.

This chapter discusses pollution control techniques for 

coal-, residual oil-, natural gas- and wood-fi red boilers. 

The technologies and methods described are used to 

control fi ne particulate matter (PM2.5), sulfur dioxide 

(SO2) and nitrogen oxides (NOx) emissions from electricgenerating boilers (EGUs, discussed in Chapter 7) as well 

as from industrial and commercial boilers (discussed in 

Chapter 6 and in several of the sector-specifi c chapters of 

this report).

The control options discussed in this chapter are divided 

into four categories: (1) fuel switching and fuel cleaning, 

(2) combustion control technologies, (3) post-combustion 

control technologies, and (4) multi-pollutant control 

technologies. Switching to a cleaner-burning fuel or 

treating a fuel prior to combustion can reduce PM2.5, SO2

and NOx emissions, as well as a host of air toxic emissions. 

Combustion controls are primarily used to control NOx

emissions. Post-combustion controls generally target a 

single pollutant or category of pollutants. Multi-pollutant 

controls, as the name implies, are integrated systems 

designed to reduce several pollutants.

This chapter focuses exclusively on the technical options 

for reducing emissions from boilers. Chapter 7, Electric 

Generating Units; Chapter 6, Industrial and Commercial 

Boilers; and the sector-specifi c chapters (e.g., pulp and 

paper) include policy options for addressing boiler 

emissions.

Fuel Switching

Fuel switching encompasses several different control 

options. One option is blending lower-polluting fuels 

to reduce overall emissions. For example, many boiler 

Chapter 5

Boiler Technologies 
 Chapter 5 - Boiler Technologies 43

operators blend lower sulfur (subbituminous) coals with 

higher sulfur (bituminous) coals to reduce SO2 emissions. 

Another option is to substitute a lower emitting fuel 

entirely. For example, power plants will sometimes 

switch from using oil to natural gas during the summer 

ozone season to comply with seasonal NOx emissions 

requirements, or switch fuels year round to reduce annual 

emissions.

The feasibility of fuel switching will depend in part on 

the characteristics of the plant and the particular type of 

fuel change being considered. Many plants will be able 

to switch from high-sulfur to low-sulfur bituminous coal 

without serious diffi culty, but switching from bituminous 

to subbituminous coal may present greater challenges 

and costs. In some instances, fuel switching will require 

signifi cant investment and modifi cations to an existing 

plant. Switching to a lower sulfur coal can affect coal 

handling systems, boiler performance, PM controleffectiveness and ash handling systems (Rastogi, 2001; 

Rubin, 2001).

In general, for fuel substitution to be practical, there must 

be a suitable replacement fuel available at an acceptable 

cost. Boiler owners must evaluate the availability, 

performance, and cost of the alternatives. While most 

industrialized areas have access to a variety of fuels, some 

fuels may not be practical in certain locations. Natural 

gas is generally supplied by pipeline. Owners of facilities 

that are not located near existing pipelines may fi nd it 

expensive to arrange for a natural gas supply. Since coal 

is typically supplied by railroad and the characteristics 

of coal from different areas of the country vary widely, 

some types of coal may not be available at a given location 

because of shipping costs.

In some cases, fuel switching will have an impact on 

the performance of the boiler (even if it is a fuel of the 

same type with different characteristics). For example, 

many coal-fi red boilers burn low-sulfur Powder River 

Basin (PRB) coal to reduce SO2 emissions. However, 

while the PRB coals are inherently low in sulfur, they 

also have a lower heating value than eastern bituminous 

coal. Facilities must test-burn the fuel and typically must 

limit their use of PRB coal (e.g., a 15/85 percent blend of 

PRB/bituminous) to avoid having to de-rate the unit or 

face other operating diffi culties. Fuel substitution is not 

feasible for sources where the substitution would require 

excessive retrofi ts or would entail substantial performance 

losses (EPA, 1998). 

If alternative fuels are available, retrofi t costs are 

Table 5.1

Average Fuel Prices

Fuel

2004 2005 (Jan.-Sep.)

Price Price per MMBtu Price Price per MMBtu

Bituminous coala $30.56/ton $1.27 NA NA

Subbituminous coala $8.12/ton $0.41 NA NA

Residual oilb

(1% sulfur or more)

$0.835/gal $5.57 $1.081/gal $7.21

Residual oilb 

(less than 1% sulfur)

$0.692/gal $4.61 $0.923/gal $6.15

Distillate oilc $1.31/gal $9.36 $1.845/gal $13.18

Natural gasd $6.09 - $6.43/103 cf $5.97 - $6.30 $6.94 - $7.50/103 cf $6.80 - $7.35

NA = Not Available

MMBtu = million British thermal units

a. Average price from U.S. Energy Information Administration (EIA), Table 31. Average Open Market Sales Price of Coal by State and 

Coal Rank, 2004, available at: http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html. Price per MMBtu calculated assuming a heat 

content of 12,000 Btu per pound for bituminous coal and 10,000 Btu per pound for subbituminous coal.

b. Average price from EIA, Table 19. U.S. Refi ner Residual Fuel Oil Prices, Average Sales to End Users, available at: http://www.eia.doe.

gov/pub/oil_gas/petroleum/data_publications/petroleum_marketing_monthly/current/pdf/pmmtab19.pdf. Price per MMBtu calculated 

assuming a heat content of 150 MMBtu per thousand gallons.

c. Average price from EIA, U.S. No. 2 Distillate Prices by Sales Type, Industrial Consumers, available at: http://tonto.eia.doe.gov/dnav/

pet/pet_pri_dist_dcu_nus_a.htm. Price per MMBtu calculated assuming a heat content of 140 MMBtu per thousand gallons. Note that 

distillate oil is not normally used in electric generating boilers.

d. Average industrial and electric industry price from EIA, U.S. Natural Gas Prices. Available at: http://tonto.eia.doe.gov/dnav/ng/ng_pri_

sum_dcu_nus_a.htm. Price per MMBtu calculated assuming a heat content of 1,020 MMBtu/106 standard cubic feet (scf).
44 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

reasonable, and performance loss is manageable, fuel 

prices will tend to be the determining factor in deciding 

whether fuel switching is viable. Table 5.1 reports recent 

(2004–2005) average fuel prices for coal, oil and natural 

gas.

The replacement fuel must also provide a meaningful 

reduction in emissions to merit the change. The effect that 

the replacement fuel has on emissions of pollutants other 

than the pollutant in question should also be considered. 

For example, switching to low-sulfur coal to reduce SO2

emissions may increase PM emissions. (See discussion 

of electrostatic precipitator (ESP) to understand why this 

might occur.)

Switching from residual oil to natural gas or distillate 

oil is one option for reducing emissions. Residual oil 

contains higher concentrations of sulfur and ash compared 

to distillate oil and natural gas. Fuel oils are classifi ed by 

number: No. 1 and No. 2 fuel oils are both distillate oils. 

No. 5 and No. 6 fuel oils are residual oils. No. 4 fuel oil 

can be distillate or a mixture of residual and distillate 

(EPA, 1998).

EPA estimates greater than a 90 percent reduction in PM2.5

emissions when switching from residual oil to distillate 

oil or natural gas. Note, however, that distillate oil is not 

normally used in electric-generating boilers (EPA, 1998).

Table 5.2 provides EPA estimates of the potential 

PM2.5 reductions associated with switching away from 

bituminous or subbituminous coal to lower emitting fuels.

Table 5.3 shows EPA’s estimates of the potential reductions 

in SO2 emissions from fuel substitution.

Switching from coal to natural gas reduces NOx emissions 

(EPA, 1998). Switching from residual oil to distillate oil or 

natural gas can result in limited NOx emissions reductions, 

but achieving signifi cant NOx reductions requires the 

application of combustion and post-combustion control 

technologies.

Fuel Cleaning

Coal washing is widely practiced in the U.S. to remove 

impurities (e.g., sulfur) and to increase the coal’s heating 

value.

Conventional (physical) coal washing techniques remove 

ash and sulfur from coal by crushing the fuel and 

separating the different components in a liquid bath, such 

as water.1 The lighter coal particles fl oat to the top of the 

bath for recovery, while the heavier impurities sink to the 

bottom for removal. 

Sulfur in coal exists in two forms. The fi rst is as an 

inorganic form called “pyrite.” The second is organic 

sulfur, which is chemically bound in the molecular 

structure of coal itself. Conventional coal washing 

removes only inorganic sulfur and nitrogen—physical 

cleaning will not remove organic sulfur.

1. Coal washing generates solid and liquid wastes that must be 

properly handled and disposed of in order to avoid contaminating surface and ground water supplies.

Table 5.2

Estimated Potential Direct PM2.5 Emissions Reductions with Fuel Switching away from Coal

Sector Original Fuel

Switch to 

Subbituminous

(% Reduction)

Switch to 

Residual Oila

(% Reduction)

Switch to Natural 

Gas 

(% Reduction)

Switch to Distillate 

Oilb

(% Reduction)

Industrialc Bituminous Coale 21.4 7.4 93.1 99.1

Subbituminous 

Coalf

– – 91.2 98.8

Utilityc,d Bituminous Coale 21.4 14.8 97.5 –

Subbituminous 

Coalf

– – 96.8 –

a. Assuming ash content of 0.03% by weight and sulfur content of 2.5% by weight.

b. Assuming ash content <0.01% by weight and sulfur content of 0.22% by weight; typically not used in utility boilers.

c. Based on emissions from dry bottom boilers.

d. Utilities tend to operate more effi ciently than industrial units and have lower resulting PM emissions.

e. Assuming ash content of 8.6% by weight.

f. Assuming ash content of 5.2% by weight.

Source: EPA, 1998
 Chapter 5 - Boiler Technologies 45

Coal washing removes varying degrees of ash and sulfur, 

depending on the type of coal being washed and the 

cleaning process used. Organic sulfur, which cleaning 

does not remove, accounts for 35–75 percent of the total 

sulfur content in Illinois Basin coals, for example (TVA, 

2005). Physical coal cleaning typically removes 40–50 

percent of the pyritic sulfur in typical llinois coal. The 

end result is a 20–25 percent reduction in SO2 emissions 

(Southern Illinois University, 2005).

In addition to lowering air emissions, coal washing also 

increases the heating value of the fuel. This lowers the 

transportation cost of the fuel per unit of energy, offseting 

the costs associated with the coal washing. Coal washing 

also reduces the maintenance costs associated with the 

boiler. According conference paper, unplanned outages—

resulting from the use of coal with higher ash and sulfur 

content—can cost a modest size coal plant millions of 

dollars in lost revenue (Cole, 2004).

Chemical and biological cleaning methods have been 

developed in an effort to remove organic sulfur, but these 

are used only infrequently. 

The cost of coal cleaning varies depending on the type of 

coal and is offset by reduced ash disposal requirements, 

increased generation per ton of coal, reduced SO2 and 

PM emissions, decreased transportation costs, reduced 

equipment wear and tear and lower operating and 

maintenance costs.

Combustion Control Technologies

Combustion controls, also known as combustion 

modifi cations, attempt to suppress the formation of NOx

within the boiler by controlling peak fl ame temperatures, 

oxygen concentrations, and residence times in the active 

combustion zones. The most common technologies are 

low-NOx burners (LNBs) and overfi re air (OFA), used 

alone or in combination.

There are two basic pathways of NOx formation within 

a boiler. First, the combustion process releases nitrogen 

bound in the fuel, which combines with oxygen to form 

“fuel NOx.” Second, high combustion temperatures break 

apart stable nitrogen molecules in the air, which then 

recombine with oxygen to form “thermal NOx.”2 Fuel NOx

is sensitive to oxygen concentrations in the combustion 

zone and can be limited by using a lower nitrogen fuel or 

by limiting oxygen availability during the early stages of 

combustion. Thermal NOx is sensitive to temperature and 

oxygen availability and can be controlled by increasing the 

size of the combustion zone or by reducing the temperature 

in the combustion zone. Relatively little thermal NOx is 

formed at temperatures below 1,700 degrees Fahrenheit 

(

o

F) (Srivastava, 2005).

Bituminous and subbituminous coals usually contain 

between 0.5 and 2 percent nitrogen by weight. Fuel 

nitrogen can account for as much as 80 percent of total NOx

emissions from coal combustion (EPA, 1995). Fuel NOx is 

also the more important NOx-forming mechanism in boilers 

that burn residual oil. Thermal NOx is the dominant NOxforming mechanism in units fi red by distillate oils; it is the 

only NOx-forming mechanism in natural gas combustion 

systems (EPA, 1995). Wood-fi red boilers normally operate 

at lower combustion temperatures relative to other fuels 

(around 1,500°F for wood-fi red boilers compared to over 

2,000°F for natural gas- or oil-fi red boilers). Since woodfi red boilers normally burn at lower temperatures, the 

units have inherently lower NOx emissions (Washington 

DEC, 2003). This is especially true for older and smaller 

wood-fi red boilers. As a result, NOx combustion control 

technologies are not applicable to wood-fi red boilers. 

However, post-combustion NOx controls (such as selective 

catalytic reduction) can be effective on wood-fi red boilers 

that operate at higher temperatures. (Newer and larger 

wood-fi red boilers use technologies that allow for higher 

2. NOx also forms from the reaction of molecular nitrogen with hydrocarbon radicals (prompt NOx). However, prompt NOx accounts for only 

a small fraction of total NOx formation and is not the focus of control 

efforts (Srivastava, 2005; Washington DEC, 2003).

Table 5.3

Estimated SO2 Emissions Reductions with Fuel Switching

Original Fuel

Subbituminous Coal 

(Percent Reduction)

Distillate Oilb

(Percent Reduction)

Natural Gas

(Percent Reduction)

Bituminous Coal 72.9 91.2 99.9

Subbituminous Coal – 69.5 99.9

Residual Oila – 91.5 99.9

Distillate Oilb – – 99.7

a. Assuming ash content of 0.03% by weight and sulfur content of 2.5% by weight.

b. Assuming ash content <0.01% by weight and sulfur content of 0.22% by weight; typically not used in utility boilers.

Source: EPA, 1998
46 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

combustion temperatures.)

Some of the combustion techniques described below 

involve running the boiler slightly ineffi ciently in order 

to create a cooler combustion zone. Generally speaking, 

the lower the fl ame temperature, the less NOx is formed. 

However, operating the boiler to create a cooler combustion 

zone results in incomplete combustion and can increase 

PM, carbon monoxide (CO) and volatile organic compound 

(VOC) emissions.

Combustion controls have been installed on more than 

50 percent of coal-fi red boilers in the electric generating 

sector; however, only a small percentage of industrial 

boilers have combustion controls (NESCAUM, 2005).

Low-NOx Burners

LNBs reduce the formation of both thermal and fuel NOx

by staging the combustion process to produce fuel-rich and 

fuel-lean zones within the combustion fl ame (EPA, 1999). 

LNBs and OFA (discussed below) are widely used with 

coal-fi red boilers (Srivastava, 2005). According to the U.S. 

Department of Energy (DOE), LNBs are now installed on 

approximately 75 percent of the suitable coal-fi red electric 

generating capacity in the U.S. (DOE, 2005). According 

to EPA, LNBs and fl ue gas recirculation (discussed below) 

are the two most common combustion control techniques 

for natural gas-fi red boilers (EPA, 1995). 

Table 5.4 lists the NOx reduction potential and estimated 

costs for LNBs and LNBs with OFA on coal-fi red boilers, 

as well as the costs and reduction potential of LNBs with 

OFA and fl ue gas recirculation on oil- and natural gas-fi red 

boilers. LNBs and OFA have little impact on operating 

costs; hence, selection is driven primarily by the capital or 

retrofi t costs of the technology (NESCAUM, 2005). Table 

5.4 is specifi c to industrial boilers. NESCAUM reports 

a cost-effectiveness for LNBs of $200–$500 per ton of 

NOx removed for boilers in the electric generating sector 

(NESCAUM, 2005). The Midwest Regional Planning 

Organization (RPO) reports a cost-effectiveness of $200–

$1,000 for LNBs for a coal-fi red boiler (Midwest RPO, 

2005).

LNBs are capable of reducing coal plant emissions to 

roughly 0.25–0.65 pounds per million British thermal 

units (lb/MMBtu), depending on coal type and combustion 

conditions (DOE, 2005). DOE is currently working to 

develop a next generation of LNBs that will be capable 

of achieving an emissions rate comparable to the control 

levels currently achievable with post-combustion controls. 

Pilot studies using these LNBs have achieved an emissions 

rate below 0.15 lb/MMBtu with some ranks of coal. This 

is equivalent to a 70–75 percent emissions reduction 

(Richards, 2002).

Overfi re Air

OFA, or staged combustion, diverts a portion of the 

Table 5.4

Estimated Costs (2004$) and Reduction Potential for Low-NOx Burners, Overfi re Air, and Flue 

Gas Recirculation on Industrial Boilers

Boiler Fuel Type

Control 

Technology

NOx Reduction 

Potentiala

Boiler Size 

(MMBtu/hr)

Capital Cost 

($/MMBtu/hr)b

Cost 

Effectiveness 

($/ton removed)b

Coal LNB 50% 100 5,100 500–3,000

LNB 50% 250 3,900 400–2,300

LNB/OFA 50%–65% 100 7,300 600–4,400

LNB/OFA 50%–65% 250 5,500 500–3,300

Oil LNB/OFA 30% 100 2,600 600–5,300

LNB/OFA 30% 250 1,900 500–4,000

LNB/OFA/FGR 30%–50% 100 4,000 600–11,000

LNB/OFA/FGR 30%–50% 250 3,000 500–8,600

Natural gas LNB/OFA 60% 100 2,500 600–11,000

LNB/OFA 60% 250 1,900 400–8,000

LNB/OFA/FGR 80% 100 4,000 700–12,300

LNB/OFA/FGR 80% 250 3,000 500–9,400

a. From Table III-4 in NESCAUM, 2005

b. From Table III-4 in NESCAUM, 2005. Rounded to the nearest 100.
 Chapter 5 - Boiler Technologies 47

combustion air (i.e., the air supplied to the burner) from 

the burners to the region above the burner zone. This 

two-stage combustion process lowers the combustion 

temperature in the boiler, reducing NOx formation. OFA is 

frequently paired with LNBs when used on coal-, natural 

gas-, and oil-fi red boilers (Davis, 2000).

As a stand-alone modifi cation to a coal-fi red boiler, OFA 

can reduce NOx emissions up to 30 percent. Combined 

systems can achieve greater reductions. OFA in 

combination with LNBs can reduce NOx formation by 

greater than 50 percent. Table 5.4 provides estimates of 

the capital costs of installing LNBs with OFA on industrial

boilers. A more detailed presentation of these data is 

available in Chapter 6, Industrial and Commercial Boilers. 

The capital costs for LNBs with OFA on a coal-fi red utility

boiler are estimated to be $15,000–$25,000 per MW or 

$1,500–$2,500 per MMBtu per hour (Davis, 2000).3 The 

Midwest RPO reports a cost-effectiveness of $250–$600 

per ton removal for OFA for a coal-fi red boiler (Midwest 

RPO, 2005).

Flue Gas Recirculation

Flue gas recirculation is a temperature reduction process 

that involves recirculating a portion of the fl ue gas with 

the combustion air. Recirculation lowers the combustion 

temperature, reducing NOx formation (EPA, 1999). Flue 

gas recirculation can be paired with LNBs and OFA.

Flue gas recirculation is frequently used on gas-fi red 

boilers and can be used on oil-fi red boilers (EPA, 1995). 

EPA reports a 55–65 percent reduction in NOx emissions 

using fl ue gas recirculation with natural gas-fi red boilers 

and a 15–30 percent NOx reduction with residual oil-fi red 

boilers (EPA, 1995). 

LNBs and OFA are frequently used in combination with 

fl ue gas recirculation to reduce NOx emissions (EPA, 1999). 

Table 5.4 provides cost and control-effi ciency estimates for 

this combination with an industrial boiler.

Atomizer Optimization/Replacement 

Oil-fi red boilers use atomizers to produce oil droplets 

small enough to burn at a reasonable rate. Mechanical 

atomizers use the pressure of the oil supply for atomization 

and thus require relatively high oil pressure for operation. 

Steam atomizers use steam (or in some cases, compressed 

air) to form droplets from the fuel; they are often able to 

form smaller droplets than mechanical atomizers.

Existing atomizers should be in good working order to 

ensure minimal particulate (unburned carbon) emissions. 

When mechanical atomizers are used for heavier fuels, 

3. Assuming a heat rate of 10,000 Btu per kilowatt-hour.

some heating of the atomizers will be necessary to lower 

the oil viscosity enough to allow proper droplet formation.

Replacement of older atomizers, or of mechanical 

atomizers with steam atomizers where cost allows, can 

reduce unburned carbon emissions and opacity on the 

order of 50 percent in some cases. Lower unburned carbon 

emissions will be refl ected in improved boiler thermal 

effi ciencies.

Reburning

Reburning, sometimes classifi ed as a combustion control 

(NESCAUM, 2005) and sometimes as a post-combustion 

control (Srivastava, 2005), involves injecting coal, oil, 

or natural gas above the primary combustion zone. The 

objective is to produce an area with hydrocarbon fragments 

that react with NOx to form other nitrogen-containing 

materials that can be reduced to nitrogen (Srivastava, 

2005). Generally, it is more economical for a facility to 

use the same fuel for reburning as it does for primary 

combustion, although there are exceptions.

Reburning can be used on natural gas-, oil- or coal-fi red 

boilers to control NOx emissions. In order to use coal as 

a reburning fuel, it must be fi nely ground, which requires 

additional pulverizing equipment. A number of coalfi red electric generators with natural gas-fi red reburning 

equipment have stopped using the equipment because of 

the rising cost of natural gas (Srivastava, 2005).

Worldwide, over 40 boilers have installed reburning 

equipment with reported or expected NOx reductions of 

25–78 percent. In the U.S., reburning equipment has been 

installed on 26 coal-fi red utility boilers since 1991. Of 

those, only four are currently operating. The remaining 

installations are either on decommissioned boilers or are 

not operational for site-specifi c reasons such as the cost of 

natural gas (Srivastava, 2005). EPA estimates that 50–70 

percent NOx reductions can be achieved with reburning on 

natural gas-fi red boilers (EPA, 1999).

Capital costs for reburn range from $15 to $30 per kilowatt 

(kW) for reburn when gas is the primary fuel, and from 

$30 to $60 per kW when coal is the primary fuel. Costeffectiveness is estimated at $500–$2,000 per ton of NOx

removed (NESCAUM, 2005).

Post-Combustion Controls

Post-combustion controls are pollution control devices that 

are placed downstream of the boiler to remove pollutants 

from the fl ue gases. Post-combustion controls are effective 

at removing PM (including PM2.5), SO2 and NOx. The 

sections below are organized by pollutant and control 

technology, beginning with PM controls.
48 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

PM Post-Combustion Controls

Particulate control is an issue only with coal-, oil-, and 

wood-fi red combustion units. Natural gas-fi red boilers are 

inherently low emitting. 

Fabric Filters

A fabric fi lter, more commonly known as a baghouse, 

traps particulates in the fl ue gas before they exit the stack. 

Fabric fi lters are made of a woven or felted material in the 

shape of a cylindrical bag or a fl at, supported envelope. The 

system includes a dust collection hopper and a cleaning 

mechanism for periodic removal of the particulates. 

Initially, industrial facilities (e.g., steel manufacturing) 

were the primary users of baghouses, but over the past two 

decades the thermal resistivity of fi lter material has been 

improved and the use of fabric fi lters on coal-fi red utility 

boilers has increased (Davis, 2000).

EPA does not recommend using fabric fi lters for boilers 

that use oil exclusively. Particles from oil combustion tend 

to clog the fi lter. EPA recommends using fabric fi lters for 

wood- and coal-fi red utility and industrial boilers (EPA, 

1998).

According to EPA, a fabric fi lter on a coal-fi red utility 

boiler can capture up to 99.9 percent of total particulate 

emissions and 99.0–99.8 percent of PM2.5. Fourteen 

percent of coal-fi red utility boilers in the U.S. have 

installed fabric fi lters (EPA, 2004).

Table 5.5 summarizes cost estimates for three common 

types of fabric fi lters. The fi rst of these fi lters—a fi lter 

with a mechanical shaker—is effective on coal-fi red 

boilers, while the other two types of fi lters are effective 

on both coal- and wood-fi red boilers. The various types 

of fabric fi lters have similar collection methods; however, 

they differ in terms of the methods used to clean the fi lters 

and remove the dust. Costs are reported in terms of the 

gas fl ow of the unit. The quantity of fl ue gas to be handled 

is one of the key parameters that dictates the sizing and 

hence the cost of a fabric fi lter.

Over the past several years, the development of new fi lter 

media and special coating and fi nishing techniques has 

extended the life and improved the performance of fabric 

fi lters. Modern computer controls continuously monitor 

and adjust the cleaning process, improving emissions 

control and lowering costs (IEA, 2003).

A baghouse downstream of an ESP (described below) 

provides high rates of PM2.5 removal. Because the 

precipitator removes the bulk of the particulate burden, 

the baghouse can be relatively small, reducing its cost. 

For example, the Compact Hybrid Particulate Collector 

(COHPAC) is a technology patented by the Electric 

Power Research Institute (EPRI) in which a baghouse is 

placed downstream of an existing ESP to improve overall 

particulate collection effi ciency. A hybrid PM collection 

system can achieve 99.99 percent particulate control for 

all particles from 0.01 to 50 micrometers (μm) in diameter, 

and can be retrofi t to an existing ESP (IEA, 2003).

Electrostatic Precipitators

An ESP uses an electrical charge to separate the particles 

in the fl ue gas stream under the infl uence of an electric 

fi eld. In brief, an ESP works by imparting a positive or 

negative charge to particles in the fl ue gas stream. The 

particles are then attracted to an oppositely charged plate 

or tube and removed from the collection surface to a 

hopper by vibrating or rapping the collection surface.

There are four common types of ESPs: dry wire-pipe, 

dry wire-plate, wet wire-pipe, and wet wire-plate. Older 

ESPs are generally of the wire-pipe design, while newer 

ones are generally of the wire-plate design. The standard 

technology for utility and industrial boilers is the dry wireplate ESP (EPA, 2003e). Wet ESPs are used in situations 

where the material to be collected is wet, sticky, fl ammable, 

or explosive, or has a high resistivity (EPA, 2003g).

Table 5.5

Estimated Costs and Reduction Potential for Fabric Filtersa

Filter Type

PM Reduction 

Potential

Capital 

Cost ($/scfm)

O&M 

Cost ($/scfm)

Cost-Effectiveness 

($/ton removed)

Mechanical shaker 

cleaned

95%–99.9% 8–72 4–24 37–303

Pulse jet cleaned 95%–99.9% 6–26 5–24 42–266

Reverse-air cleaned 95%–99.9% 9–85 6–27 53–337

SCFM=standard cubic feet per minute

a. Filters are effective on PM2.5 but the cost estimates are for removal of all particulates.

Source: EPA, 2003a; EPA, 2003b; EPA, 2003c
 Chapter 5 - Boiler Technologies 49

An ESP can be installed at one of two locations. Most 

ESPs are installed downstream of the air heater, where 

the temperature of the fl ue gas is between 130°C–180°C 

(270°F–350°F). An ESP installed downstream of the air 

heater is known as a “cold side” ESP. An ESP installed 

upstream of the air heater, where fl ue gas temperatures are 

signifi cantly higher, is known as a “hot side” ESP. 

Seventy-two percent of coal-fi red utility boilers in the U.S. 

have installed cold side ESPs and 11 percent have installed 

hot side ESPs (EPA, 2001a); 80 percent of all ESPs in the 

U.S. are used in the electric industry (EPA, 2003e). 

The effectiveness of an ESP depends in part on the 

electrical resistivity of the particles in the fl ue gas. Coal 

with a moderate to high amount of sulfur produces 

particles that are more readily controlled. Low-sulfur coal 

produces a high-resistivity fl y ash that is more diffi cult 

to control. The effectiveness of an ESP also varies 

depending on particle size. A dry ESP can capture greater 

than 99 percent of total PM from a coal-fi red boiler, while 

capturing 80 to 95 percent of PM2.5 (EPA, 1998; EPA, 

2003e; EPA, 2004). 

Experience with wet ESPs on utility and industrial boilers 

is limited. However, wet ESPs are generally considered 

to be more effi cient than dry ESPs at removing PM2.5 and 

their usage is increasing. Wet ESPs are reportedly capable 

of achieving 99 percent PM2.5 removal effi ciency (Altman, 

2003).

Table 5.6 lists cost ranges (in 2002 dollars) for 

conventionally designed dry and wet wire-plate ESPs 

operating under typical conditions.

As indicated, a large number of existing coal-fi red boilers 

have ESPs installed. Several options are available for 

improving the performance of these systems (EPA, 

2005c):

Improved Monitoring. Improved monitoring 

includes the installation of an opacity monitor or a 

continuous PM monitoring device.

•

Conditioning Agents. Conditioning agents 

change the properties of the ash resulting from 

combustion. Conditioning with ammonia, hydrated 

sodium carbonate/bicarbonate, or other agents can 

improve particulate collection effi ciency.

Upgraded ESPs. Upgrades include increasing the 

size of the precipitator, replacing older “weighted 

wire” electrodes with modern “rigid discharge” 

electrodes, and adding advanced electronic controls.

Wet Scrubbers

Wet scrubbers are also used to control particulate 

emissions. The two most frequently utilized wet scrubbers 

for PM control are condensation scrubbers and venturi 

scrubbers. Condensation scrubbers are designed to control 

PM with a diameter of 0.25–1.0 μm (EPA, 2003k). Venturi 

scrubbers are effective in controlling both PM less than or 

equal to 10 μm in diameter (PM10) and PM2.5 (EPA, 2003j). 

Wet scrubbers can also be used to control SO2 emissions; 

SO2 scrubbers are used in fl ue gas desulfurization, a 

technology described below.

Venturi scrubbers are used to control PM emissions from 

utility, industrial, and commercial coal-, residual oiland wood-fi red boilers. Table 5.7 presents estimates of 

particulate collection effi ciency and cost for condensation 

and venturi scrubbers.

SO2 Post-Combustion Controls

Flue Gas Desulfurization

Flue gas desulfurization (FGD) uses a sorbent—usually 

lime or limestone—to remove SO2 from the exhaust gases 

of a fossil-fuel-fi red boiler. FGD scrubbers can be wet 

or spray dry. FGD scrubbers can be used on coal-fi red 

utility and industrial boilers. Outside of the U.S., FGD 

scrubbers have also been used on heavy oil-fi red boilers. 

Approximately 85 percent of the systems in the U.S. 

are wet systems, 12 percent are spray dry, and 3 percent 

are dry systems (EPA, 2003m). FGD scrubbers have 

been applied to coal-fi red boilers ranging in size from 

•

•

Table 5.6

Estimated Costs (2002$) and Reduction Potential for Dry and Wet Wire-Plate ESPs

Filter Type

PM2.5 Reduction 

Potential

Capital Cost 

($/scfm)

O&M Cost 

($/scfm)

Cost-Effectiveness 

($/ton removed)

Dry wire-plate 96%–98% 10–33 3–35 35–236

Wet wire plate 99% 20–40 5–40 48–520

SCFM = standard cubic feet per minute

Source: EPA, 2003e; EPA, 2003g
50 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

50 MMBtu per hour to 15,000 MMBtu per hour (EPA, 

2003m).

FGD scrubbers are capable of reduction effi ciencies 

ranging from 50 percent to 98 percent. Historically, wet 

FGD scrubbers have the highest removal effi ciencies 

(greater than 90 percent) while dry FGD scrubbers have 

the lowest. However, newer dry scrubbers are capable of 

effi ciencies near 90 percent (EPA, 2003m).

Table 5.8 shows EPA cost estimates for wet and spray dry 

scrubbers (the two most common FGD scrubber types) for 

various sizes of electric boilers.

Dry Sorbent Injection

Dry sorbent injection involves the direct release of lime 

(or other suitable sorbent) into the ductwork or boiler 

upstream of a PM control device. The SO2 in the fl ue 

gas reacts with the powdered sorbent, which can then be 

collected by the downstream PM control device. The SO2

control-effi ciency of existing dry injection systems ranges 

from 40 to 60 percent when using lime or limestone, 

and up to 90 percent using other sorbents (e.g., sodium 

bicarbonate) (EPA, 2005b). This option is likely to be most 

cost-effective for smaller units, less than 300 megawatts 

(MW), because of the lower capital costs of the technology 

($70 per kW) relative to a wet scrubber (Argus Air Daily, 

2005). 

NOx Post-Combustion Controls

Selective Catalytic Reduction

Selective catalytic reduction (SCR) is a well developed and 

widely applied post-combustion NOx control technology 

(Davis, 2000). SCR reduces NOx emissions using a 

reducing agent and a catalyst. SCR is typically used on 

electric industry boilers, industrial boilers, process heaters, 

gas turbines, and reciprocating internal combustion 

engines that burn fossil fuels. SCR systems have been 

used on coal- and natural gas-fi red electric utility boilers 

ranging in size from 25 MW to 800 MW. The technology 

is commercially available for oil-fi red boilers but not 

widely demonstrated (Davis, 2000). SCR retrofi ts on 

existing boilers can increase capital costs by over 30 

percent compared to installing SCR on a new unit (EPA, 

2003h).

SCR can be used as a stand-alone technology or in 

combination with other NOx control technologies (e.g., 

LNBs or fl ue gas recirculation). Capital costs for SCR 

are substantially higher than other NOx control options 

described in this chapter (EPA, 2003h).

EPA estimates a NOx control-effectiveness of 80–95 

Table 5.7

Estimated Costs and Reduction Potential for Wet Scrubbers

Scrubber Type

PM Reduction 

Potential

Capital Cost 

($/scfm)

O&M Cost 

($/scfm)

Cost-Effectiveness 

($/ton removed)

Condensation Scrubbersa >99% 6 2.5 59

Venturi Scrubbersb 70%–90% 2.5–21 4.4–120 70–2,400

a. 1993$

b. 2002$

Source: EPA, 2003j, 2003k

Table 5.8

Estimated Costs (2001$) and Reduction Potential for Wet and Spray Dry FGD Scrubbers

Scrubber 

Type

SO2 Reduction 

Potential

Unit Size 

(MMBtu/hr)

Capital Cost 

($/MMBtu)

O&M Cost 

($/MMBtu)

Cost-Effectiveness 

($/ton removed)

Wet >90% >4,000 1,000–2,500 20–80 200–500

Wet >90% <4,000 2,500–15,000 80–200 500–5,000

Spray dry 80%–90% >2,000 400–1,500 40–100 150–300

Spray dry 80%–90% <2,000 1,500–15,000 100–3,000 500–4,000

Source: EPA, 2003m
 Chapter 5 - Boiler Technologies 51

Table 5.9

Estimated Costs (1999$) for SCR Technology

Unit Type Capital Cost O&M Cost

Cost-Effectiveness 

($/ton removed)

Industrial coal boiler 

(350 MMBtu)

$10,000–$15,000 per MMBtu/hr $300 per MMBtu/hr 2,000–3,000

Industrial oil, gas, or wood 

boiler (350 MMBtu)

$4,000–$6,000 per MMBtu/hr $450 per MMBtu/hr 1,000–3,000

Coal-fi red electric industry 

boiler (100-850 MW)

$50,000–$110,000 per MW $0.4–$4.2 million per year 1,000–1,500

Source: EPA, 2001b; EPA 2003h; NESCAUM, 2005

percent for coal-fi red electric industry boilers (EPA, 

2001b). The main factors in determining the emissions 

reduction potential of this technology are temperature, 

the amount of reducing agent, injection grid design and 

catalyst activity.

EPA includes SCR in its Integrated Planning Model (IPM) 

as one of the post-combustion NOx controls available for 

coal-, oil-, and natural gas-fi red boilers. The Agency 

assumes a 90 percent NOx removal effi ciency for SCR 

systems installed on coal units and an 80 percent NOx

removal effi ciency for SCR systems installed on oil- and 

natural gas-fi red boilers (EPA, 2002).

SCR systems require a large volume of catalyst material; 

as a result, capital costs are signifi cantly higher than for 

other types of NOx controls. Table 5.9 summarizes cost 

estimates for SCR. The costs in Table 5.9 assume a high 

capacity factor and annual NOx control. These assumptions 

can signifi cantly affect operation and maintenance (O&M) 

costs and hence overall cost-effectiveness.

The cost of retrofi tting an oil- or gas-fi red boiler with SCR 

controls is estimated at about one-half to one-third the 

cost of retrofi tting a coal-fi red boiler because gas- and oilfi red boilers require less catalyst than a coal-fi red boiler 

(NESCAUM, 2005). 

Selective Non-catalytic Reduction

Selective non-catalytic reduction (SNCR) is a postcombustion NOx control technology that has been installed 

on a wide range of boiler confi gurations, including 

coal-, natural gas-, biomass-, and waste-fi red units. There 

are hundreds of SNCR systems installed in the U.S. 

on boilers ranging in size from 50 MMBtu/hr to 6,000 

MMBtu/hr (EPA, 2003i).

As shown in Table 5.10, SNCR operating alone has a NOx

reduction potential of 30–70 percent. Combined with other 

controls, such as LNBs, SNCR can achieve reductions of 

65–75 percent (EPA, 2003i; Srivastava, 2005).

EPA includes SNCR as one of the post-combustion NOx

controls available for coal-, oil-, and natural gas-fi red 

boilers in IPM. The Agency assumes a 35 percent NOx

removal effi ciency for SNCR systems installed on coal 

units and a 50 percent NOx removal effi ciency for SNCR 

systems installed on oil- and natural gas-fi red boilers 

(EPA, 2002).

Table 5.10 also shows EPA cost estimates (in 1999 dollars) 

for SNCR systems installed on industrial boilers greater 

than 100 MMBtu per hour in size. The cost of a retrofi t 

is approximately 10–30 percent greater than the cost 

of SNCR for a new boiler (EPA, 2003i). SNCR systems 

Table 5.10

Estimated Costs (1999$) and Reduction Potential of SNCR Technology

Unit Type

NOx Reduction 

Potentiala Capital Cost O&M Cost

Cost-Effectiveness 

($/ton removed)

Industrial boilers 

(>100 MMBtu/hr)

30%–70% $900–$2,500 per MMBtu/hr

($9,000–$25,000 per MW)

$100–$500 per MMBtu/hr

($1,000–$5,000 per MW)

400–2,500a

2,000–3,000b

a. annual NOx control

b. seasonal NOx control

Source: EPA, 2003i; Srivastava, 2005
52 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

have a lower capital cost than SCR, but higher operating 

costs. EPA reports a wide range of cost-effectiveness 

estimates for SNCR due to site-specifi c conditions. SNCR 

is considered an effective control option for seasonal NOx

reductions since capital costs are relatively low (EPA, 

2003i).

The Midwest RPO reports a cost-effectiveness of $800–

$1,500 for SNCR for a coal-fi red boiler (Midwest RPO, 

2005).

Multi-Pollutant Control 

Technologies

Control technology manufacturers are developing a new 

generation of multi-pollutant controls designed to capture 

multiple air pollutants more cost-effectively than existing 

single-pollutant controls. In addition to better performance 

and reduced cost, multi-pollutant control technologies can 

offer the following benefi ts:

fewer system components, reducing space 

requirements;

reduced operational complexity;

lower auxiliary power requirements, resulting in less 

impact on heat rate (i.e., effi ciency) of a unit;

lower collateral emissions (e.g., ammonia slip); and

reduced water consumption, wastewater discharge 

and solid waste (in some cases with production of a 

marketable co-product) (Khan, 2005).

Dozens of new multi-pollutant control technologies have 

been developed and tested in recent years. A few of 

these technologies have advanced to the point where they 

are now commercially available. This section provides 

descriptions of commercially available multi-pollutant 

technologies—including cost and performance estimates 

where available—together with descriptions of the most 

promising of the emerging technologies.

Commercially Available MultiPollutant Control Technologies

LoTOxTM

Low temperature oxidation (LoTOxTM) employs ozone 

injection to oxidize NOx and elemental mercury for 

subsequent removal in a wet scrubber. The technology 

is licensed by the BOC Group and is being marketed as a 

control option for NOx that is less expensive than SCR and 

also has the ability to remove mercury. LoTOxTM can be 

used on new or existing units (BOC Group, 2005).

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An on-site ozone generator is used to produce the ozone 

feed for the system from an oxygen source. Once injected 

into the LoTOxTM reactor, the ozone oxidizes the NOx and 

elemental mercury present in the fl ue gas. The oxidized 

compounds can then be removed in a downstream wet 

scrubber (EPA, 2003; MJB&A, 2004).

Full-scale commercial LoTOxTM systems have been 

installed successfully in a variety of industries, including 

the steel and recycling sectors. The technology has been 

demonstrated on a pilot-scale only at coal-fi red electric 

generating facilities. 

The LoTOxTM system is reported to control 70–95 percent 

of the NOx in fl ue gas to levels below 0.15 lb/MMBtu 

(Khan, 2005). BOC normally recommends installing 

LoTOxTM alone when inlet NOx levels are below 0.3 lb/

MMBtu. Above 0.3 lb/MMBtu inlet NOx, LoTOxTM is 

recommended as part of an integrated control approach, 

meaning that it would operate in series with an alternate 

control process such as LNBs, OFA, or selective autocatalytic reduction. By combining two technologies, users 

may be able to achieve NOx reductions similar to those 

achieved by an SCR system alone, but at lower capital and 

operating costs (EPA, 2005a).

Total mercury removal rates of 90 percent from all coal 

ranks have been estimated for this process, although 

additional testing at the pilot- and full-scale level are 

needed to demonstrate mercury removal capabilities 

(MJB&A, 2004).

When used with FGD, 95 percent of SO2 can be removed. 

According to BOC Group, LoTOxTM enhances the SO2

removal effi ciency of the FGD system by approximately 

5 percent (Keeth, 2003). CO2 emissions increases of 1.0–

2.5 percent can be expected due to the auxiliary power 

requirements associated with the system (EPA, 2005a).

Suppliers estimate capital costs for the LoTOxTM process 

to be $35–$70 per kW (for LoTOxTM only; not including 

FGD), depending on the inlet NOx level and unit size (EPA, 

2005a). Annual operating and maintenance costs are 

estimated to range from 1.7 to 2.4 mills/kWh (for LoTOxTM 

used in conjunction with selective auto-catalytic reduction, 

not including FGD) (MJB&A, 2004).4

MobotecSystemTM

The MobotecSystemTM combines three different control 

technologies to reduce NOx, CO, SO2, mercury and other 

heavy metal emissions.

The MobotecSystemTM is based on three separate 

technologies that can be installed together or individually: 

(1) rotating opposed fi red air (ROFA); (2) rotary mixing of 

4. One mil is equal to 1/10 of one cent (or $0.001).
 Chapter 5 - Boiler Technologies 53

chemicals (Rotamix); and (3) an in-duct catalyst (SCR) that 

may be used in conjunction with the previous two systems 

for lower cost than a standard SCR system operated alone 

(Mobotec, 2005).

ROFA affects combustion and NOx emissions directly 

by staging the furnace and turbulently mixing the 

fl ue gas with high-velocity secondary air. 

Rotamix is an advanced SNCR system that makes 

use of the well-mixed fl ue gas and high-velocity air 

achieved with ROFA to inject and evenly distribute 

various chemicals (e.g., ammonia, urea, trona, 

limestone) or additional fuel (e.g., reburn gas) 

into the fl ue gas to remove NOx, SO2, and heavy 

metals (including mercury). Because ROFA and 

Rotamix are generally designed as one system, the 

MotobecSystemTM is considered a multi-pollutant 

control option. 

In-duct SCR is an independent NOx control option 

that can be used in conjunction with ROFA and 

Rotamix to increase the overall NOx controleffectiveness of the MobotecSystemTM to a level 

comparable to that achievable with a full size, 

stand-alone SCR system (approximately 90 percent) 

(Coombs, 2004). Upstream NOx reductions by the 

ROFA and Rotamix technologies decrease the SCR 

costs by reducing the amount of catalyst required to 

achieve 90 percent control effi ciency.

There are currently 18 ROFA-Rotamix installations in the 

U.S. and 17 in Sweden (mainly on stoker-fi red, fl uidizedbed, and dry-bottom boilers burning coal, heavy fuel 

oil, wood wastes, and municipal waste). The system can 

reportedly be employed with most fuel types and fi ring 

confi gurations (EPA, 2005a). 

In terms of potential O&M impacts, ROFA can be expected 

to improve combustion effi ciency and lower CO emissions. 

However, the system can lead to reductions in superheat 

and reheat temperatures. The impact of the system on 

O&M costs is very site-specifi c (depending on the boiler 

design, operating conditions, and fuel characteristics). 

The system requires auxiliary power to operate, as well 

as inputs of various chemicals such as ammonia, urea, 

limestone, and trona (EPA, 2005a).

Air pollutant removal effi ciencies for the MobotecSystemTM

are estimated at 50–85 percent for NOx, 60–90 percent 

for SO2, and 65–90 percent for mercury (Keeth, 2003; 

Coombs, 2004; Bierman, 2005). The ROFA system alone 

reduces NOx emissions by 40–60 percent. The ROFARotamix systems combined reduce NOx emissions by a 

total of 60–80 percent, and the complete system, with 

the in-duct SCR, reduces NOx emissions by 90 percent. 

Several units, operating commercially, have demonstrated 

the NOx reduction capability of the system. There is less 

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experience with the system in reducing SO2 and mercury 

emissions (Haddad, 2003a). The fi rst commercial 

application of the system for mercury control is currently 

planned at two Minnesota power plants (Duluth News 

Tribune, 2005).

The MobotecSystemTM is marketed as a cost-effective 

alternative to SCR, based primarily on its lower catalyst 

use (Haddad, 2003b; Coombs, 2004). The total capital 

costs for a 400 MW and a 700 MW MobotecSystemTM are 

estimated at $10 million and $15 million, respectively. The 

annual operating costs for a 400 MW and 700 MW system 

are estimated at $100,000 and $175,000, respectively. 

The system also consumes energy to run the ROFA fans 

(Haddad, 2003b).

Advanced Dry Scrubbing

Advanced dry scrubbing (ADS) is designed to improve 

the performance of conventional spray dry FGD units 

and is primarily designed for SO2 and mercury control 

on incinerators and coal-fi red boilers burning low- to 

medium-sulfur coals. The process involves the reaction 

of hydrated lime slurry with exhaust gases in an absorber 

vessel to capture SO2, sulfur trioxide (SO3), hydrochloric 

acid (HCl), and mercury. ADS technology utilizes a 

fl uidized bed or a fl ash dryer for the reactor, with a recycle 

loop to enhance lime utilization (MJB&A, 2004).

For the most part, ADS designs represent variations 

on circulating fl uid bed (CFB) technology, with design 

features specifi c to each vendor. A CFB reactor is a 

vertical reactor in which a dense material bed of recycled 

products (ash and sorbent) ensures rapid cooling and a 

high degree of contact between gases and solids. The fl ue 

gas fl ows upward through the bed, with sorbent typically 

being sprayed as a slurry into the gas upstream of the bed. 

The ash and sorbent product is recycled back to the reactor 

through a dedicated cyclone integral to the system, or 

directly from the fi nal particulate collection device (ESP 

or fabric fi lter).

Specifi c variants of the technology offered by major 

vendors include (EPA, 2003):

circulating dry scrubbers (CDS), offered by LURGI;

gas suspension absorbers (GSA), offered by FLS 

Miljo;

refl ux circulating fl uidized bed absorbers (RCFB), 

offered by WULFF; and

rapid absorption process (RAP), offered by Beaumont 

Environmental.

While not widely used in the U.S., all four CFB-based 

technologies are commercially available and have been 

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54 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

installed in the U.S. and abroad.

O&M impacts associated with ADS technologies are 

similar to those associated with conventional spray dryers. 

Potential impacts include: increased pressure loss, need 

for increased auxiliary power, increased loading of solids 

on the downstream particulate collectors, corrosion, and 

increased water requirements. The magnitude of these 

impacts is a function of specifi c design characteristics and 

operating conditions; it also depends on whether the ESP 

or fabric fi lter is new.

ADS technology is reportedly capable of removing more 

than 95 percent of the SO2 and SO3 in fl ue gas. Less 

information is available on mercury removal rates, which 

vary signifi cantly depending on coal type, operating 

conditions, and the presence of other pollution control 

devices in the plant. EPA has reported mercury removal 

rates as high as 97 percent and as low as 50 percent 

using the LURGI CDS system. The opportunity to add 

“dedicated” mercury sorbent is predicted to increase 

overall mercury removal potential (EPA, 2005a).

Capital cost estimates for ADS technologies range from 

$50 to $150 per kW, depending on the specifi c technology 

(Keeth, 2003; EPA, 2005):

 FLS Miljo reports a cost of $150/kW for GSA. 

LURGI estimates capital costs for its CDS system at 

$140/kW.

According to WULFF, the capital cost of RCFB at a 

275 MW plant in Austria was $90/kW.

Beaumont Environmental reports a cost of $50/kW 

for a RAP installation at a 150 MW plant.

ReACT 

The Japanese electric generating company J-POWER owns 

the ReACT multi-pollutant removal system, in which fl ue 

gas passes through a two-stage bed of activated coke. In 

the fi rst stage, sulfur oxides are largely removed through 

oxidation to sulfuric acid. The second stage involves the 

injection of ammonia to decompose NOx into nitrogen and 

water. The adsorber is a moving bed, which is withdrawn 

for regeneration in a separate vessel. Mercury adsorbed 

on the activated coke is released in vapor form during 

regeneration and is captured on a selenium fi lter, where it 

is fi xed as a stable compound. The technology can produce 

saleable byproducts, including raw sulfur and sulfuric acid 

(MJB&A, 2004; Khan, 2005).

ReACT has not been used in North America, but is being 

used at 17 coal, sintering, incinerator, and oil- and refusederived fuel installations worldwide (EPA, 2005a). JPOWER is marketing this technology as a more cost-

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effective option for SO2, NOx and mercury control than 

the combination of SCR and wet FGD. According to 

J-POWER, ReACT offers the following advantages (JPOWER, 2005):

higher removal rates for elemental and oxidized 

mercury;

smaller space requirements;

much less water consumption;

lower auxiliary power requirements;

no SO3 slip;

fewer retrofi t items (duct, fans, etc.);

no need to retrofi t the air preheater and stack; and

availability of collected activated coke for reuse. 

Due to the high heat capacity of the activated coke 

system, it takes longer than a conventional plant to reach 

the operating temperature of the de-NOx process, which 

means that NOx emissions will be higher during start-up 

or that more time will be required for plant start-up. Other 

O&M impacts are not known, mainly because of the lack 

of experience in the U.S. Required auxiliary power is 

estimated to be 0.70 percent of gross output, compared to 

1.0–2.5 percent for a wet FGD system (EPA, 2005a).

ReACT reportedly has demonstrated removal rates of 

greater than 95 percent for SO2, 10–50 percent for NOx, 

greater than 90 percent for mercury and greater than 95 

percent for PM (with an ESP). J-POWER is targeting a 

NOx removal rate of 70 percent. NOx control-effectiveness 

is higher when SO2 concentrations at the inlet of the 

adsorber are lower. The amount of ammonia injected also 

affects NOx reduction, as do the oxygen concentration 

of the fl ue gas and the inlet gas temperature (J-POWER, 

2005; Khan, 2005).

According to J-POWER, capital costs for the ReACT 

system (including the cost of equipment to make 

byproducts) are projected to range from $100 to $160 per 

kW for units 300–900 MW in capacity. Variable operating 

costs are estimated to range from 1.7 to 2.6 mills per kWh 

(J-POWER, 2005; Keeth, 2003).

Emerging Multi-Pollutant Control 

Technologies

SOx-NOx-ROx Box

The SOx-NOx-ROx Box (SNRB) offered by Babcock 

and Wilcox combines the removal of SO2, NOx, and 

particulates in one unit—a high temperature baghouse. 

The baghouse, located before the air heater, operates in 

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 Chapter 5 - Boiler Technologies 55

the 425°C–455°C (800°F–850°F) temperature range. SO2

removal involves injecting calcium- or sodium-based 

sorbent, sodium carbonate and sodium bicarbonate into 

the fl ue gas upstream of the baghouse. NOx removal 

is accomplished by injecting ammonia to reduce NOx

selectively in the presence of an SCR catalyst placed on 

the high-temperature ceramic fi lter bags of the baghouse. 

The baghouse also removes particulates.

The SNRB system can be applied to both new and existing 

units and has been demonstrated successfully at Ohio 

Edison’s Burger Unit No. 5 (a 156 MW boiler burning 

high-sulfur bituminous coal). However, demonstration on 

a larger scale is needed to better assess the performance 

and economics of this technology.

Based on pilot-scale testing, the SNRB can remove 90 

percent of the NOx and 80–90 percent of the SO2 in fl ue 

gas, while reducing PM levels to less than 0.02 lb/MMBtu. 

The only potential O&M impact of this technology relates 

to its effects on the life expectancy of fabric fi lters. The 

SNRB fi lters are ceramic, incorporating a catalyst for NOx

control, and their reliability is affected by both mechanical 

and thermal stress due to changing operating conditions 

and clean-up of the bags. 

The supplier of these systems estimates that capital costs 

for a 150 MW retrofi t would be $253 per kW (in constant 

1994 U.S. dollars), assuming 3.5 percent sulfur coal, 

baseline NOx emissions of 1.2 lb/MMBtu, a 65 percent 

capacity factor, and 85 percent SO2 and 90 percent NOx

removal. No estimates of O&M costs are available (Keeth, 

2003; EPA, 2005a).

ECO®

Powerspan’s ECO® technology removes PM2.5, SO2, NOx

and mercury from the fl ue gas of coal-fi red power plants. It 

treats the fl ue gas in three steps to achieve multi-pollutant 

removal, using a barrier discharge reactor, an ammonia 

scrubber, and a wet ESP. An absorber tower contains the 

ammonia scrubber and precipitator. Mercury collected 

from the absorber tower is removed from the liquid stream 

with an activated carbon fi lter. Since this technology 

includes a scrubber, its primary market is unscrubbed 

existing plants and new plants burning medium- to highsulfur bituminous coal (EPA, 2003; MJB&A, 2004; Khan, 

2005).

The ECO® technology is in the demonstration stage. 

Powerspan has been operating a 50 MW commercial 

demonstration unit at FirstEnergy Corporation’s R.E. 

Burger Plant since February 2004. The demonstration 

unit is located downstream of the plant’s ESP and the 

treated fl ue gas is returned to the existing plant ductwork 

just before the stack. In September 2005, FirstEnergy 

announced plans to install an ECO® system at the 

company’s Bay Shore Plant Unit 4 (215 MW) (Boyle, 

2005).

The main O&M impact of the ECO® process is its 

auxiliary power consumption. Powerspan estimates that 

approximately 3 percent of the plant’s output is needed for 

the ECO® process to reduce inlet NOx levels from 0.30–

0.05 lb/MMBtu. Also, cooling water is required for the 

wet ESP and heating is required for the acid recovery and 

ash drying. While these auxiliary power requirements 

do not present a technical challenge, they will have some 

impact on a plant’s mass and energy balances, as well as 

on its overall effi ciency. At this point, there is not enough 

information to assess the magnitude of this impact, but it 

is not expected to be substantial (EPA, 2005a).

Based on testing performed to date, ECO® technology is 

estimated to reduce SO2 emissions by 98 percent, NOx

emissions by 90 percent, and mercury emissions by 85 

percent. The 50 MW demonstration at the R.E. Burger 

Plant achieved results of this magnitude (Boyle, 2005).

Powerspan and others performed a detailed cost estimate 

for an ECO® unit at AmerenUE’s Sioux plant. The capital 

cost of the system for this 510 MW installation was 

estimated at $120.4 million. This fi gure includes costs 

for the fertilizer plant and balance-of-plant modifi cations 

(EPA, 2005a). FirstEnergy estimates the cost of the 

system at its 215 MW Bay Shore Plant, including a 

fertilizer processing plant, to be approximately $100 

million (FirstEnergy, 2005). Although the performance 

and costs of this technology remain uncertain, the results 

of the demonstration project suggest that an estimated cost 

of $200 per kW is reasonable. Projected O&M costs are 

1.5 mills/kWh (Keeth, 2003; EPA, 2005a). 

Powerspan has entered into an alliance with Wheelabrator 

Air Pollution Control to commercialize the ECO® 

technology (Powerspan, 2005). As the process is scaled, 

the main uncertainties relate to whether it can replicate the 

performance that it has achieved at smaller scale. Also, 

the economic benefi ts of the technology are dependent, 

in part, on the ability to market the fertilizer co-product 

produced by the process. Powerspan expects the capital 

costs of the technology to be approximately 10–20 percent 

less than a combination of conventional technologies that 

achieves similar performance levels, and the operating 

costs are generally expected to be lower depending on a 

host of factors (Boyle, 2005).

PahlmanTM Process

EnviroScrub’s PahlmanTM Process is a closed-loop dry 

sorbent system comprised of two discrete steps. One 

step involves capturing the target pollutants—NOx, SOx, 

mercury, and particulates—using PahlmaniteTM dry 
56 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

mineral sorbent compounds. The other step involves 

the regeneration of the spent or partially spent sorbent 

compounds for reuse and separation, and the isolation 

of useful byproducts for use in fertilizers and industrial 

chemicals. The PahlmaniteTM sorbents are low-density 

oxides of manganese in the form of a fi ne black powder. 

The sorbent is injected in a reactor, which operates at a 

temperature between ambient temperature and 320°F. 

According to the supplier, the technology can be used on 

different types of reactors and can be applied to new units 

or retrofi tted to existing units (EPA, 2003; MJB&A, 2004; 

Khan, 2005).

The PahlmanTM technology is in a pilot-scale stage. A 

trailer-mounted pilot plant has been tested at a number 

of power plants, using fl ue gas slipstreams (1,000 scfm) 

(EPA, 2005a). Results from testing at Minnesota Power’s 

Boswell Station indicate that the technology achieved SO2

reductions above 99 percent, NOx reductions of 94–97 

percent, and mercury reductions of up to 67 percent (Khan, 

2005).

O&M impacts for this technology are unknown. Auxiliary 

power demand is expected to increase, but no specifi c 

estimates are available (EPA, 2005a). According to the 

supplier, capital costs for a 500 MW plant are projected to 

be approximately $150 per kW (Keeth, 2003). The supplier 

projects variable O&M costs at approximately 1.45 mills/

kWh (EPA, 2005a).

The technology is still at an early development stage 

and requires further demonstration and assessment for 

a more comprehensive picture of its cost-effectiveness. 

Removal effi ciencies for mercury and particulates need 

to be demonstrated. The pollutant removal and sorbent 

regeneration steps have been commercially demonstrated 

individually, but not in an integrated system. An integrated 

20 MW demonstration project is currently planned for 

installation at the Boswell Station (EPA, 2005a).

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Pollution Control Technology Fact Sheet: Fabric Filters—

Pulse-Jet Cleaned Type (EPA-452/F-03-025), July 2003. 

www.epa.gov/ttn/catc/dir1/ff-pulse.pdf. (2003b)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Fabric Filters—

Reverse-Air/Reverse-Jet Cleaned Type With & Without 

Sonic Horn Enhancement (EPA-452/F-03-026), July 2003. 

www.epa.gov/ttn/catc/dir1/ff-revar.pdf. (2003c)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Dry Electrostatic 

Precipitator (ESP)—Wire-Pipe Type (EPA-452/F-03-

027), July 2003. www.epa.gov/ttn/catc/dir1/fdespwpi.pdf. 

(2003d)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Dry Electrostatic 

Precipitator (ESP)—Wire-Plate Type (EPA-452/F-03-

028), July 2003. www.epa.gov/ttn/catc/dir1/fdespwpl.pdf. 

(2003e)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Wet Electrostatic 

Precipitator (ESP)—Wire-Pipe Type (EPA-452/F-03-

029), July 2003. www.epa.gov/ttn/catc/dir1/fwespwpi.pdf. 

(2003f)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Wet Electrostatic 

Precipitator (ESP)—Wire-Plate Type (EPA-452/F-03-

030), July 2003. www.epa.gov/ttn/catc/dir1/fwespwpl.pdf. 

(2003g)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Selective 

Catalytic Reduction (SCR) (EPA-452/F-03-032), July 2003. 

www.epa.gov/ttn/catc/dir1/fscr.pdf. (2003h)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Selective NonCatalytic Reduction (SNCR) (EPA-452/F-03-031), July 

2003. www.epa.gov/ttn/catc/dir1/fsncr.pdf. (2003i)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Venturi 

Scrubber (EPA-452/F-03-017), July 2003. www.epa.gov/

ttn/catc/dir1/fventuri.pdf. (2003j)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Condensation 

Scrubber (EPA-452/F-03-010), July 2003. www.epa.gov/

ttn/catc/dir1/fcondnse.pdf. (2003k)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Flue Gas 

Desulfurization (FGD) (EPA-452/F-03-034), July 2003. 

www.epa.gov/ttn/catc/dir1/ffdg.pdf. (2003m)

U.S. Environmental Protection Agency (EPA). Emission 

Control Technologies for Coal-fi red Power Plants (OAR2003-0053-0014), January 16, 2004.

U.S. Environmental Protection Agency (EPA). 

Multipollutant Emission Control Technology Options 

for Coal-fi red Power Plants (EPA-600/R-05/034), March 

2005. (2005a)

U.S. Environmental Protection Agency (EPA). “Standards 

of Performance for Electric Utility Steam Generating 

Units for Which Construction Is Commenced After 

September 18, 1978; Standards of Performance for 

Industrial-Commercial-Institutional Steam Generating 

Units; and Standards of Performance for Small IndustrialCommercial-Institutional Steam Generating Units,” 

Federal Register, 70(38): 9711, February 28, 2005. (2005b)

U.S. Environmental Protection Agency (EPA). Evaluation 

of Potential PM2.5 Reductions by Improving Performance 

of Control Devices: PM2.5 Emission Estimates, Final 

Report, prepared by E. H. Pechan & Associates, Inc.; and 

RTI International, September 27, 2005. (2005c)

Washington State Department of Ecology (DEC). Hog 
 Chapter 5 - Boiler Technologies 59

Fuel Boiler RACT Determination (Publication 03-02-009), 

April 2003. www.ecy.wa.gov/pubs/0302009.pdf.

World Bank Group. “Sulfur Oxides: Pollution Prevention 

and Control,” Pollution Prevention and Abatement 

Handbook, July 1998. http://lnweb18.worldbank.org/essd/

essd.nsf/GlobalView/PPAH/$File/46_soxc.pdf.
60 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Chapter 6

Industrial and Commercial Boilers

Introduction

Industrial and commercial boilers combust large quantities 

of fuel to produce steam and hot water for a variety of uses. 

These boilers represent about 40 percent of all energy use 

in the industrial and commercial sectors (EEA, 2005). 

Industrial boilers usually drive mechanical equipment 

or heat process materials (e.g., petroleum). Commercial 

boilers (which include institutional boilers) generally 

provide space heating and hot water for hotels, hospitals 

and other large facilities. Some boilers produce electrical 

power for on-site industrial consumption, sometimes 

cogenerating steam and electricity.

In this chapter we discuss fi ne particulate matter (PM2.5), 

sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions 

from the industrial and commercial boiler source category 

and the opportunities for controlling these emissions. 

The discussion includes boilers fi red by coal, residual oil, 

natural gas and wood. Boilers fi red by process byproducts 

(e.g., black liquor solids in pulp and paper recovery boilers) 

are discussed in other chapters. We do not address boilers 

fi red by other fuels (e.g., distillate oil, tires or biogas) 

because they contribute a small share of emissions.

In order to avoid excessive repetition, the more detailed 

technical discussion of emissions control opportunities for 

industrial, commercial and electric power sector boilers 

appears in Chapter 5, Boiler Technologies.

Sector Profi le

In the U.S., there are an estimated 43,000 industrial boilers 

with a total capacity of 1,600,000 million British thermal 

units per hour (1.6 million MMBtu/hr), and 120,000 

commercial boilers with a total capacity of 1.1 million 

MMBtu/hr. Industrial boilers tend to be larger than 

commercial boilers, with an average size of 36 MMBtu/hr 

as compared to 9.6 MMBtu/hr. Industrial boilers also tend 

to have higher utilization rates (EEA, 2005). Boilers in the 

electric industry are larger still. 

The universe of industrial and commercial boilers is 
 Chapter 6 - Industrial and Commercial Boilers 61

have been grouped according to their primary fuel type. 

Based on the data presented, more than half of industrial 

boilers in the U.S. have capacities under 10 MMBtu/hr; 

however, these small boilers account for only a small share 

of industrial boiler capacity. Coal-fi red industrial boilers 

larger than 250 MMBtu/hr and natural gas-fi red industrial 

boilers between 10 and 100 MMBtu/hr account for the 

largest share of capacity in the industrial boiler sector, 

with each accounting for about 19 percent of total capacity. 

There are 594 coal-fi red boilers larger than 250 MMBtu/

hr, and 10,738 natural gas-fi red boilers between 10 and 

100 MMBtu/hr. Natural gas-fi red industrial boilers larger 

than 250 MMBtu are the next largest category, with 572 

boilers accounting for 16 percent of total industrial boiler 

capacity.

Emissions

Table 6.2 provides a breakdown of 1999 annual emissions 

in the U.S. from industrial and commercial boilers by 

fuel type, based on data from EPA’s National Emission 

Inventory (NEI). Note that the commercial boiler numbers 

include institutional boilers.

Although there are almost triple the number of commercial 

boilers in the U.S. compared to industrial boilers, the vast 

majority of them are small. The predominance of small 

boilers combined with the large number (85 percent) 

that are natural gas-fi red, means that commercial boilers 

contribute far fewer emissions when compared to the 

industrial boiler category. 

According to the current inventory data, despite being 

a relatively clean burning fuel, natural gas-fi red boilers 

account for about 40 percent of PM2.5 emissions from 

the industrial and commercial boiler sectors. The sheer 

number of natural gas-fi red boilers (about half of industrial 

boilers and 85 percent of commercial boilers) is partly 

responsible for this result. However, during a review of the 

2002 NEI, EPA concluded that the emissions factors used 

to estimate PM2.5 emissions from natural gas combustion 

in the 2002 NEI and prior inventories were too high. EPA 

diffi cult to characterize for a number of reasons, the 

primary one being that some boilers, commercial boilers 

in particular, are so small that little detailed information is 

routinely collected on them. Additionally, data on boilers 

are reported in a variety of categories—by fuel type, 

boiler type and industry sector. As a result, inventory and 

emissions data are far from precise.

In support of a recent rulemaking, EPA estimated the 

number of industrial boilers in the U.S. by capacity and 

fuel type.1

 According to the estimates, 49 percent of 

industrial boilers are fi red by natural gas, 29 percent by 

coal, 10 percent by residual oil, 4 percent by wood and 7 

percent by other fuels (Alvis, 2002). 

According to a review of industrial and commercial boiler 

populations completed by Energy and Environmental 

Analysis (EEA) for Oak Ridge National Laboratory in 

2005, most data on boilers at commercial facilities are 

incomplete. EEA estimates that 85 percent of commercial 

boilers are fi red by natural gas, 11 percent by oil, 1.3 

percent by coal and 2 percent by other fuels. Of the 

130 large capacity commercial boilers (larger than 250 

MMBtu/hr), EEA estimates that 80 are coal-fi red and 50 

are gas-fi red. 

Table 6.1 summarizes the number of industrial and 

commercial boilers by capacity.

Table 6.1 shows that while there are many more 

commercial than industrial boilers in operation in the U.S., 

the majority of them are smaller than 10 MMBtu/hr. This 

difference in capacity is refl ected in the emissions data 

presented below.

At the end of this chapter, Table 6A.1 provides additional 

information on the industrial boiler population by capacity 

and predominant fuel type. Units with multiple fuels are 

a small proportion of the total number of units, and they 

1. In support of the Industrial/Commercial/Institutional Boiler and Process Heaters National Emission Standards for Hazardous Air Pollutants 

(EPA, 2004).

Table 6.1

Industrial and Commercial Boilers in the U.S. by Capacity

Capacity Range 

(MMBtu/hr) Industrial Boilers

% of Total Industrial 

Boilers Commercial Boilers

% of Total 

Commercial Boilers

0-10 23,800 56% 480,650 95%

10-100 14,860 35% 24,890 5%

100-250 2,560 6% 1,120 <1%

>250 1,480 3% 130 <1%

TOTAL 42,700 100% 506,790 100%

Source: Alvis, 2002; EEA, 2005
62 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 6.2

Industrial and Commercial Boiler Sector Emissions

PM2.5 SO2 NOx

Fuel Tons/Year

% of Sector 

Total Tons/Year

% of Sector 

Total Tons/Year

% of Sector 

Total

Industrial boilers

Coal 12,242 7% 728,809 57% 288,393 33%

Bituminous &

subbituminous

12,091 7% 670,175 53% 266,756 31%

Anthracite &

lignite

151 0% 58,634 5% 21,638 3%

Oil 10,417 6% 178,025 14% 80,015 9%

Residual 8,332 5% 160,876 13% 62,565 7%

Distillate 2,085 1% 17,149 1% 17,450 2%

Natural gas 58,630 35% 51,952 4% 253,456 29%

Wood/bark 32,568 20% 17,369 1% 73,636 9%

Other 36,474 22% 188,935 15% 94,843 11%

Industrial 

boilers subtotal

150,331 90% 1,165,090 91% 790,343 92%

Commercial boilers

Coal 2,961 2% 84,033 7% 22,772 3%

Bituminous &

subbituminous

2,417 1% 79,291 6% 20,737 2%

Anthracite &

lignite

545 0% 4,742 0% 2,035 0%

Oil 1,616 1% 19,092 1% 9,074 1%

Residual 449 0% 14,254 1% 6,570 1%

Distillate 1,167 1% 4,838 0% 2,504 0%

Natural gas 7,553 5% 3,022 0% 33,681 4%

Wood/bark 3,230 2% 2,818 0% 4,065 0%

Other 477 0% 2,034 0% 3,024 0%

Commercial 

boilers subtotal

15,837 10% 110,999 9% 72,617 8%

Industrial and 

commercial 

boiler sector 

total

166,168 100% 1,276,089 100% 862,960 100%

Source: EPA, 2005a, based on facilities listed under Source Classifi cation Codes starting with 102 and 103
 Chapter 6 - Industrial and Commercial Boilers 63

intends to revise the 2002 NEI, dramatically reducing 

(by 95 percent) its estimates of the PM2.5 emissions from 

natural gas combustion (EPA, 2005d). It is important to 

note that the fi gures reported in Table 6.2 refl ect the earlier

methodology.

While coal-fi red boilers account for 29 percent of 

industrial boiler capacity and 6 percent of the number of 

industrial boilers, they account for more than 60 percent 

of SO2 emissions and a third of NOx emissions from the 

industrial and commercial boiler sector. They were 

assumed to account for 9 percent of PM2.5 emissions from 

the industrial and commercial boiler sector, although this 

will change with the revision of the PM2.5 estimates for 

natural gas-fi red units. In the commercial sector, coalfi red boilers account for almost all the SO2 emissions.

Industrial wood-fi red boilers account for 20 percent of 

industrial and commercial boiler PM2.5 emissions, despite 

the fact that they are only 4 percent of industrial boiler 

capacity and 2 percent of the industrial boiler inventory. 

This share will also increase with the revision of the PM2.5

estimates for natural gas-fi red units.

The “Other” categories in Table 6.2 includes about a fi fth 

of all PM2.5 emissions from the industrial and commercial 

boiler sector. A large percentage of these emissions come 

from boilers fi ring process materials (discussed in the 

specifi c sector chapters). However, many of the control 

options discussed in this chapter and in Chapter 5 can be 

used or modifi ed for use on process fuel-fi red boilers.

SO2 compounds form when sulfur in coal or oil is oxidized 

during combustion. Fuel oil sulfur content depends on 

grade, but it is generally less than 1 percent. Natural 

gas has virtually no sulfur and its combustion therefore 

produces almost no SO2. About 95 percent of the sulfur 

in fossil fuels is released as gaseous SO2 when combusted 

(EPA, 1995).

NOx formation results from the thermal fi xation of 

atmospheric nitrogen in the combustion fl ame (“thermal 

NOx”), and from oxidation of nitrogen in the fuel (“fuel 

NOx”). Bituminous and subbituminous coals usually 

contain from 0.5 to 2 percent nitrogen by weight. Fuel 

nitrogen can account for as much as 80 percent of total 

NOx emissions from coal combustion (EPA, 1995). Fuel 

NOx is also the more important NOx-forming mechanism 

in residual oil-fi red boilers, but thermal NOx dominates in 

units fi ring distillate oils.

Table 6.3 shows the emissions rates of uncontrolled 

industrial and commercial boilers by fuel type. While 

individual boiler units may have emissions rates different 

from those in the table (depending on the boiler type), 

the table is intended to provide a sense of the range of 

emissions rates for uncontrolled boilers.

As a further point of reference, in developing the control 

Table 6.3

Emissions Rates for Uncontrolled Industrial and Commercial Boilers by Fuel Type

Fuel Type

Emissions Rates (lb/MMBtu)

PM2.5 SO2 NOx

Coal (high-sulfur)a 0.11–0.37b 5.25–5.70 0.36–1.65

Coal (low-sulfur)c 0.11–0.37 0.875–0.95 0.36–1.65

Residual Oild 0.026–0.046 0.6–1.04 0.13–0.37

Natural Gase 0.007 0.0005 0.098–0.230

Woodf 0.25–0.72 0.008–0.025 0.04–0.49

lb/MMBtu = pounds per million British thermal units

a. Assumes sulfur content = 3% and ash content = 5%.

b. Compared to low-sulfur coal, high-sulfur coal produces only slightly more direct PM, since boilers convert virtually all of the sulfur in 

coal to SO2. SO2 may lead to secondary PM, but the SO2 column in the chart (as opposed to the PM column) reveals this characteristic.

c. Assumes sulfur content = 0.5% and ash content = 5%; assumes heat value of 10,000 MMbtu/lb.

d. For #6 oil, assumes sulfur content = 1% and PM coeffi cient (A) = 1.49.

For all oil types, assumes heat value = 0.15 MMbtu/gallon.

For all oil types, assumes normal fi ring (i.e., not tangential).

e. Assumes heat value of 1,020 Btu/standard cubic feet (scf), 100% conversion of fuel sulfur to SO2, and sulfur content = 2,000 

grains/106 scf.

f. Assumes heat value of 0.0045 MMBtu/lb. 

Source: EPA, 1995; Davis, 2000
64 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

cost estimates for the Clean Air Interstate Rule (CAIR), 

EPA assumed uncontrolled emissions for industrial boilers 

of 0.72 pounds of NOx per MMBtu (lb/MMBtu) for coalfi red boilers; 0.25 lb/MMBtu for natural gas-fi red boilers; 

and 0.22 lb/MMBtu, 0.36 lb/MMBtu, and 0.5 lb/MMBtu 

for oil-fi red boilers. (The two higher oil-fi red NOx values 

were added to better refl ect the variability in inventory 

data (Khan, 2003a).) EPA conducted similar analyses for 

SO2 control technologies, but the Agency did not specify 

uncontrolled emissions rates (Khan, 2003b).

Emissions Control Opportunities

Numerous options are available for reducing PM2.5 and 

PM2.5-precursor emissions from industrial and commercial 

boilers. In general, the options fall into three categories: 

(1) improving combustion effi ciency; (2) fuel switching to 

lower emitting fuels; and (3) using control technologies 

(including combustion and post-combustion controls). The 

discussion that follows provides an overview of the control 

options for industrial and commercial boilers. A more 

detailed discussion of the controls for coal-, oil-, natural 

gas- and wood-fi red boilers, including fuel switching, is 

contained in Chapter 5, Boiler Technologies.

Improving Combustion Effi ciency 

A properly tuned and maintained boiler requires less 

fuel to generate steam effi ciently, thereby reducing the 

amount of fuel burned in the boiler, which in turn reduces 

the amount of air pollution exiting in the fl ue gas. Some 

states require boiler owners to conduct boiler tune-ups to 

optimize combustion effi ciency. For example, New York 

requires owners of small boilers (e.g., 20–50 MMBtu/hr in 

some levels of nonattainment area) to perform an annual 

tune-up (NY DEC, 2004). In general, larger boilers are 

better equipped to continuously optimize combustion 

effi ciency (e.g., by continuously monitoring oxygen and 

carbon monoxide levels in the fl ue gas), although there are 

opportunities for owners of smaller boilers as well.

Fuel Switching

Fuel switching can be an effective strategy for reducing 

PM2.5, SO2 and NOx emissions. For example, switching 

from a high-sulfur (bituminous) coal to a lower-sulfur 

(subbituminous) coal can reduce a unit’s SO2 emissions 

by more than 70 percent. However, switching to a lowersulfur coal can affect coal handling systems, boiler 

performance, PM control-effectiveness and ash handling 

systems (Rastogi, 2001; Rubin, 2001). Therefore, the 

feasibility of switching to a lower-sulfur coal will require 

a facility-specifi c determination, taking into consideration 

the cost and availability of different types of coal in 

different areas. Blending lower-sulfur and higher-sulfur 

coal has also been used to control SO2 emissions and often 

requires fewer modifi cations than a complete substitution. 

Coal blending has been successfully implemented in the 

electric generating sector (Russell, 2005).

Although expensive, switching from coal to natural gas 

produces even more dramatic results, virtually eliminating 

a plant’s SO2 and direct PM2.5 emissions and signifi cantly 

lowering NOx emissions. Switching from oil to natural gas 

is easier than switching from coal to natural gas, and many 

plants have dual oil- and gas-fi ring capability. Going from 

a higher- to a lower-sulfur residual oil or from residual 

to distillate oil is also possible, although facility-specifi c 

issues related to differences in the viscosity of the fuel may 

need to be addressed.

Fuel switching is not without its complications. The 

availability of fuel switching as a control strategy for a 

specifi c boiler will depend heavily on the location of the 

facility. For example, a facility may be unable to access 

lower-sulfur coal supplies or may lack access to a natural 

gas pipeline. Also, since transportation costs make up a 

large fraction of the delivered price of coal, the price of 

low-sulfur coal varies widely across facilities.

Chapter 5, Boiler Technologies, includes a more detailed 

discussion of fuel switching, including emissions reduction 

and cost estimates.

Boiler Control Technologies

There are two basic categories of technologies that 

are available to control emissions from industrial and 

commercial boilers: combustion controls and postcombustion controls.

Combustion controls involve modifi cations to the 

combustion process that reduce the formation of NOx in 

the boiler. The most common technologies are low-NOx

burners (LNBs) and over fi re air (OFA), used either alone 

or in combination. Flue gas recirculation (FGR) is another 

common technology, used alone or in combination with 

LNBs and OFA.

Post-combustion controls involve the application of backend control systems to capture or convert pollutants 

before they are released to the air. Post-combustion 

control technologies are available for all of the pollutants 

addressed in this report. The most common technologies 

include selective catalytic reduction (SCR) for NOx control, 

fl ue gas desulfurization (FGD) or scrubbers for SO2

control, and fabric fi lters (also known as baghouses) and 

electrostatic precipitators (ESPs) for PM control. Table 6.4 

summarizes the available technologies. Chapter 5, Boiler 

Technologies, also discusses emerging multi-pollutant 

control technologies. However, these are more likely to 

be used within the electric generating sector because of 

state and federal control requirements specifi c to electric 

generating units (EGUs). 
 Chapter 6 - Industrial and Commercial Boilers 65

In general, combustion controls involve lower capital 

investment and operating costs than post-combustion 

controls but produce more modest emissions reductions. 

LNBs and OFA can achieve a 40–60 percent reduction 

in NOx emissions, while SCR controls can achieve 70–90 

percent control. Post-combustion controls often require 

large capital expenditures with signifi cant on-going 

operating and maintenance costs. They can also make 

signifi cant energy demands, requiring a meaningful 

portion of a facility’s electricity output to operate.

To compare the various control options, we have compiled 

information on the cost-effectiveness of retrofi tting 

controls. In general, cost-effectiveness increases as boiler 

size and capacity factor (a measure of boiler utilization) 

increases. For example, EPA estimates a cost-effectiveness 

of about $1,000 per ton of NOx removed with the 

application of SCR controls on a boiler with an 85 percent 

capacity factor. With a capacity factor of 50 percent, the 

cost-effectiveness of control rises to about $2,000 per ton 

of NOx reduced (Khan, 2003a).

Table 6A.2, at the end of this chapter, summarizes the 

control-effectiveness and cost-effectiveness of retrofi t 

with NOx controls for industrial boilers. EPA based its 

calculations on three different size industrial boilers (100 

MMBtu/hr, 250 MMBtu/hr and 1,000 MMBtu/hr), at 

three different capacity factors. These control options 

are not appropriate in all situations. Selective noncatalytic reduction (SNCR) can be diffi cult to apply to 

industrial boilers that modulate or cycle frequently. SNCR 

technology injects ammonia (or urea) into the fl ue gases 

at specifi c fl ue gas temperatures. In a boiler that cycles 

frequently, the location of the fl ue gases at the specifi ed 

temperature will be constantly changing.

Table 6.5 presents similar data for retrofi t with SO2

control technologies on coal- and oil-fi red industrial 

Table 6.4

Combustion and Post-Control Control Options for Industrial and Commercial Boilers

Control Type Control 

Technology

Description Applications and Commercial 

Availability

Combustion 

controls (for NOx

control)

LNBs Burner confi guration that limits NOx

formation by controlling temperature 

profi le in burner zone.

Commercially available for tangential 

and wall-fi red boilers.

OFA Diverts some combustion air and 

reinjects it above burner zone.

Commercially available. Applicable to 

most boiler types. Must have suffi cient 

furnace height above burners.

LNBs with OFA Combination of new burner design and 

injection of air above main combustion 

zone.

Available in new boiler designs and can 

be retrofi tted to a variety of boiler types.

Reburn Injection of reburn fuel (natural gas, fuel 

oil or coal) for combustion above the 

main combustion zone.

Available but not in wide use. Must have 

suffi cient furnace height above burners.

Post-combustion 

controls

SCR Injection of ammonia (NH3) into boiler 

fl ue gas; fl ue gas then passed through 

a catalyst bed, where the NOx and NH3

react to form nitrogen and water vapor.

Available on new boilers and as retrofi t.

SNCR Injection of NH3 or urea in the convective 

pass for NOx control.

Available on new boilers and as retrofi t.

FGD (Wet 

scrubber)

Slurry of lime used to absorb SO2. Commercially available and in wide use.

FGD (Spray 

drying)

Alternative scrubbing technique using 

calcium hydroxide slurry that vaporizes 

in spray vessel for SO2 control.

Commercially available and in wide use. 

Primarily for low- to medium-sulfur fuels.

ESP Use of grounded electrodes to collect 

particles.

Commercially available and in wide use.

Fabric fi lter (or 

baghouse)

Filtering elements (bags) used to collect 

particles.

Commercially available and in wide use.
66 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

boilers.2 In two recent studies of control technologies for 

industrial boilers, both the Midwest Regional Planning 

Organization and the Northeast States for Coordinated Air 

Use Management used these data for their own analyses 

(MRPO, 2005; NESCAUM, 2005). 

Control devices for wood-fi red boilers are similar to 

control devices for fossil fuel-fi red boilers. One notable 

exception is for NOx controls. As discussed in Chapter 

5, Boiler Technologies, wood-fi red boilers burn at lower 

combustion temperatures than fossil fuel-fi red boilers 

and have lower thermal NOx emissions. This is especially 

true for older and smaller wood-fi red boilers. As a result, 

NOx combustion control technologies are not applicable 

to wood-fi red boilers. However, post-combustion NOx

controls (such as SCR or SNCR) can be effective on wood2. More information on the assumptions used to develop these estimates 

can be found in Methodology, Assumptions, and References—Preliminary NOx Controls Cost Estimates for Industrial Boilers; and Methodology, Assumptions, and References—Preliminary SO2 Controls Cost 

Estimates for Industrial Boilers (Khan, 2003a; 2003b).

fi red boilers that operate at higher temperatures. (Newer 

and larger wood-fi red boilers use technologies that allow 

for higher combustion temperatures.)

Table 6.6 includes control effi ciencies for wood- and 

combination wood- (hog fuel) fi red boilers,3

 as compiled 

by the Washington State Department of Ecology (DEC) 

for a Reasonably Available Control Technology (RACT) 

analysis (Washington DEC, 2005).

Table 6.7 summarizes the Washington DEC’s costeffectiveness data on controls for PM and acid gases 

(primarily SO2 and hydrochloric acid), for three sizes of 

wood-fi red boilers: small boilers (<3,500 lb/hr steam), 

medium size boilers (15,000-45,000 lb/hr steam), and large 

boilers (>200,000 lb/hr steam). The Department concluded 

that low-sulfur fuels were RACT for SO2, and proper boiler 

3. Combination wood or hog fuel is a biomass fuel composed of wood 

products (e.g., bark, wood, sawdust) shredded or ground into half-inch to 

6-inch pieces for fi ring.

Table 6.5

Cost-Effectiveness and Control-Effectiveness of SO2 Control Options for Retrofi t on Industrial 

Boilers

Fuel Technology

SO2

Reduction (%)

Capacity 

Factor (%)

Cost-Effectiveness ($/Ton of SO2)

100 MMBtu/hr 250 MMBtu/hr 1,000 MMBtu/hr

High-sulfur 

coala

FGD (Dry) 40 14 3,543 2,471 1,703

50 1,292 992 776

83 943 763 633

Lower-sulfur 

coalb

FGD (Dry) 40 14 4,283 2,952 1,986

50 1,504 1,131 870

83 1,075 849 697

Coal FGD (Spray 

dry)

90 14 3,920 2,611 1,500

50 1,209 842 531

83 790 569 381

High-sulfur 

coal

FGD (Wet) 90 14 3,513 2,708 1,789

50 1,046 820 563

83 664 528 373

Lower-sulfur 

coal

FGD (Wet) 90 14 4,495 3,460 2,273

50 1,326 1,036 704

83 836 661 461

Oil FGD (Wet) 90 10 10,160 7,801 5,082

50 2,126 1,654 1,109

86 1,285 1,011 693

a. Assumes sulfur content = 3.43% and ash content = 12.71%.

b. Assumes sulfur content = 2.0% and ash content = 13.2%.

Source: Khan, 2003b
 Chapter 6 - Industrial and Commercial Boilers 67

Table 6.6

Control Effi ciencies for Wood-Fired Boilers

PM Removal Effi ciency 

(%)

SO2 Removal Effi ciency 

(%)

NOx Removal Effi ciency 

(%)

Single cyclone 50–90 NA NA

Multi-cyclones >90 NA NA

Dry ESP 95.5–99.9 NA NA

Wet ESP 95.5–99.9 80–95 NA

Spray dryer w/ESP 98.5–99.9 60–75 NA

Spray dryer w/FF 99.0–99.9 65–80 NA

Dry FGD and ESP 98.5–99.9 60–70 NA

Dry FGD and FF 99.0–99.9 70–80 NA

Spray dryer, dry FGD and FF 99.0–99.9 80–90 NA

ESP and wet FGD (1) 98.5–99.9 50–60 NA

ESP and wet FGD (2) 98.5–99.9 90–95 NA

SCR/SNCR NA NA >90

Source: Washington DEC, 2005

Table 6.7

Cost-Effectiveness for Wood-fi red Boilers

Pollutant, Control Technology 

(Assumed Removal Effi ciency)

Boiler Size Cost-Effectiveness ($/ton removed)

PM, Multi-cyclone (90%) Small 180

Medium 64–83

Large 55–57

PM, Venturi scrubber (90%) Small 1,229

Medium 126–306

Large 40-56

PM, ESP (99.5%) Small 594

Medium 203–292

Large 114–130

PM, Fabric fi lter (99.5%) Small 958

Medium 147–279

Large 91–107

Acid gas (SOx and hydrochloric acid), 

FGD

Small 1,349

Medium 598–713

Large 458–479

Source: Washington DEC, 2005
68 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

reconstruction or modifi cation after June 19, 1984 and 

that have a heat input capacity greater than 100 MMBtu/

hr. The rules include different limits for NOx at facilities 

that commence construction or reconstruction after July 

9, 1997 that have a heat input capacity greater than 100 

MMBtu/hr. 

40 CFR §§60.40c, et seq. (subpart Dc) apply to 

steam generating units that commence construction, 

reconstruction or modifi cation after June 9, 1989 and 

that have a maximum design heat input capacity of 100 

MMBtu/hr or less, but greater than or equal to 10 MMBtu/

hr.

On February 27, 2006, EPA published fuel-neutral 

(except for modifi ed wood) NSPS for emissions from 

industrial, commercial and institutional steam-generating 

boilers. The new limits apply to facilities constructed, 

reconstructed or modifi ed after February 28, 2005 (EPA, 

2006).

The NSPS for existing industrial and commercial boilers 

appear in Table 6A.3, and the NSPS for new boilers appear 

in Table 6A.3-1, at the end of this chapter.

Regional Haze/Best Available Retrofi t 

Technology

Under the regional haze program, Best Available 

Retrofi t Technology (BART) applies in attainment 

and nonattainment areas to PM2.5 and PM2.5-precursor 

emissions from large sources in 26 identifi ed source 

categories, that began operation between 1962 and 1997. 

The source categories include fossil fuel-fi red boilers of 

more than 250 million Btu per hour heat input. However, 

states have not yet developed their BART rules.

New Source Review/Prevention of Signifi cant 

Deterioration

New Source Review (NSR) and Prevention of Signifi cant 

Deterioration (PSD) apply to new and modifi ed large 

stationary sources in nonattainment and attainment 

areas, respectively. The programs subject plants in 

nonattainment areas to Lowest Achievable Emission Rate 

(LAER) standards, and in attainment areas to BACT. 

Neither BACT nor LAER standards are codifi ed, because 

they are intended to refl ect technology advancements as 

they occur.

Air districts in California have made a number of BACT 

determinations for PM10 and NOx emissions from natural 

gas-fi red industrial and commercial boilers. These 

determinations are summarized in Table 6.8. 

Examples of recent determinations from EPA’s RACT/

BACT/LAER Clearinghouse for industrial boilers are 

design was RACT for NOx. 

Regulatory Authority

As we have indicated in Chapter 4, the states and federal 

government share responsibility for regulating criteria 

pollutants (e.g., PM, SO2, NOx) from stationary sources 

like industrial and commercial boilers. The federal 

government has more of the burden of regulating toxic 

air pollutants, but—for both criteria pollutants and air 

toxics—states and local areas are free under federal law 

to adopt more stringent standards than the Clean Air Act 

requires.

This section describes federal Clean Air Act standards 

for emissions of PM, SO2 and NOx from the industrial and 

commercial boiler sector.

Reasonably Available Control Technology

State Implementation Plans (SIPs) for nonattainment areas 

must include RACT for new and existing sources. RACT 

standards are non-binding federal guidelines; for volatile 

organic compounds, the guidelines are known as Control 

Technique Guidelines (CTGs). Guidelines known as 

Alternative Control Techniques (ACTs) outline the control 

technologies that are available to address NOx emissions 

from specifi c source sectors, but do not specify actual 

RACT limits. There are no sector-specifi c ACTs or CTGs 

for SO2, PM10 or PM2.5.

There are ACTs applicable to NOx emissions from 

industrial and commercial boilers, which can be found 

at www.epa.gov/ttn/catc/products.html#aptecrpts (EPA, 

1994). 

SIP writers should bear in mind that although the ACTs 

may provide a starting point, they are unlikely to represent 

the actual RACT limits that states will choose to adopt. 

That is the case because RACT standards are intended to 

refl ect advancements in technology, and most of the ACTs 

are outdated—some, seriously so. Additionally, the ACTs 

are guidelines only, not actual federal limits. Even if they 

were federal limits, many states would have the leeway 

to enact more stringent standards. And since the ACTs 

do not set limits, even state prohibitions against enacting 

more stringent standards may be inapplicable.

New Source Performance Standards

New Source Performance Standards (NSPS) apply to 

stationary sources in specifi c source categories, in both 

attainment and nonattainment areas, when they are 

constructed, reconstructed or modifi ed.

40 CFR §§60.40b, et seq. (subpart Db) apply to 

steam generating units that commence construction, 
 Chapter 6 - Industrial and Commercial Boilers 69

summarized in Table 6A.4, at the end of this chapter. 

The BACT determinations in Table 6A.4 show some 

of the emissions limits that regulators have considered 

appropriate for industrial boilers during the past ten years. 

Note that the PM emissions limits for natural gas- and 

residual oil-fi red boilers are based on good combustion 

practices, while the coal-fi red units are required to meet 

PM10 emissions limits lower than 0.05 lb/MMBtu with 

fabric fi lters.

Maximum Achievable Control Technology

Maximum Achievable Control Technology (MACT) 

standards address emissions of hazardous air pollutants 

(HAPs) from new and existing sources in identifi ed 

industry categories in both attainment and nonattainment 

areas. MACT standards apply to sources with potential 

emissions of 10 tons per year of a single HAP or 25 tons 

per year of combined HAPs. In some MACT rules, such 

as those referenced here, EPA regulates PM as a surrogate 

for HAPs. 

40 CFR §§63.7480, et seq. (subpart DDDDD) regulate 

PM emissions from industrial and commercial boilers. 

A unit is “existing” unless it commenced construction or 

reconstruction after January 13, 2003. 

The MACT standards for industrial and commercial 

boilers appear in Table 6.9.

Clean Air Interstate Rule

Under the Clean Air Interstate Rule (CAIR), there are 

federal trading programs: annual for SO2, annual for NOx

and seasonal for NOx. These programs cover electric 

generating units (EGUs), but a state can include in its 

seasonal NOx program large industrial boilers (greater 

than 250 MMBtu/hr) that are included in the NOx SIP 

Call’s NOx trading program, so long as the state adheres to 

the cap established under the SIP Call program. These are 

the only non-EGU sources that can be included in any of 

the federal CAIR trading programs without disqualifying 

the state from participation in the federal trading regimes.

Table 6.8

BACT Determinations for New Natural Gas-Fired Boilers in California

Capacity 

(MMBtu/hr) District

Startup 

Date 

PM10 NOx

Limit Control Limita Control

4.2 South Coast 

AQMD

6/2000 0.007 

lb/MMBtu

ND 2 ppmvd @ 3% O2

(~0.003 lb/MMBtu)

SCONOx Catalytic 

Absorption System

5.1 South Coast 

AQMD

6/1999 ND ND 20 ppmvd @ 3% O2

(~0.03 lb/MMBtu)

LNB, FGR

6.2 San Joaquin 

Valley 

UAPCD

6/2000 0.007 

lb/MMBtu

ND 12 ppmvd @ 3% O2

(~0.016 lb/MMBtu)

LNB

10.0 South Coast 

AQMD

4/2003 ND ND 12 ppmvd @ 3% O2

(~0.016 lb/MMBtu)

Forced internal 

recirculation

16.4 South Coast 

AQMD

2/2000 ND ND 11 ppmvd @ 3% O2

(~0.015 lb/MMBtu)

SCR

16.5 South Coast 

AQMD

ND ND ND 7 ppmvd @ 3% O2

(~0.009 lb/MMBtu)

SCR

20.9 South Coast 

AQMD

4/2000 ND ND 9 ppmvd @ 3% O2

(~0.012 lb/MMBtu)

LNB

21.0 South Coast 

AQMD

12/2000 ND ND 7 ppmvd @ 3% O2

(~0.009 lb/MMBtu)

SCR

21.5 South Coast 

AQMD

4/2002 ND ND 9 ppmvd @ 3% O2

(~0.12Btu)

LNB

ND=no data

ppmvd= parts per million on dry volume basis adjusted to 3% oxygen dry.

a. lb/MMBtu approximated as ppmvd divided by 750.

Source: California Air Resources Board BACT Clearinghouse, 2005
70 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

State and Local Policy Measures

As discussed in the Introduction to this report, state and 

local agencies are free under federal law to adopt more 

stringent standards than the Clean Air Act requires, 

although in some instances state laws limit this authority. 

SIP writers are presumably familiar with any such 

constraints under applicable local laws and regulations. 

The Introduction also outlines possible approaches for 

imposing more stringent state and local standards, such as 

requiring sources that have not yet been subject to BACT/

LAER standards to achieve those limits or imposing 

air pollution limits on sources that have heretofore been 

unregulated.

The discussion below summarizes emissions standards 

for PM, SO2 and NOx that state and local offi cials should 

consider for industrial and commercial boilers. We also 

outline other opportunities to reduce emissions from these 

sources.

Emissions Standards for New and Existing 

Industrial and Commercial Boilers

In Tables 6A.5—6A.7 , at the end of this chapter, we 

include summary information on the most stringent 

PM, SO2 and NOx emissions limits for industrial and 

commercial boilers we were able to identify, in order to 

highlight the limits that regulators have viewed as feasible 

under some circumstances. We note federal limits where 

they are more stringent than any state or local limits we 

found. 

Note that these summary tables include some BACT 

determinations for EGUs, notwithstanding that the table 

headings refer to industrial and commercial boilers. We 

include these data on account of our recommendation 

(in the section entitled “Emissions Standards for New 

and Existing EGU Boilers,” below) that where EGU 

boiler limits are more stringent than any industrial and 

commercial boiler limits, the EGU limits suggest an 

appropriate starting point for consideration of limits 

for industrial and commercial boilers greater than 250 

MMBtu/hr and even those greater than 100 MMBtu/hr.

PM. No federal or state rules or permit determinations 

currently specify PM2.5 limits for industrial and commercial 

boilers, and data on the PM2.5 fraction of emissions are 

limited. Therefore, Table 6A.5, at the end of this chapter, 

highlights PM limits, on the theory that more stringent PM 

limits will also result in reduced emissions of PM2.5. 

Some recent BACT determinations include both fi lterable 

and condensable PM,4 although federal regulatory limits 

and most BACT determinations have addressed only 

fi lterable PM. STAPPA and ALAPCO have commented 

in rulemakings that PM limits should include both. We 

discuss this issue further in Chapter 3, Fine Particulate 

Matter and Precursor Emissions. 

4. Recent permitting decisions for coal-fi red EGUs in Iowa and Wisconsin include both fi lterable and condensable PM, and set limits of 0.025 

lb/MMBtu and 0.018 lb/MMBtu, respectively (STAPPA and ALAPCO, 

2005).

Table 6.9

MACT Standards for Industrial and Commercial Boilers (40 CFR §§63.7480, et seq. (subpart 

DDDDD))

Source Category Size 

(MMBtu/hr)

PM Limit

(lb/MMBtu)

New or reconstructed Solid Fuela >10 0.025

≤ 10, >10% capacity factor 0.025

Liquid Fuelb >10 0.03

≤ 10, >10% capacity factor 0.03

Gaseous Fuelc NA No limit

Existing Solid Fuel >10 0.07

Solid Fuel-Limited Used >10 0.21

Liquid Fuel NA No limit

Gaseous Fuel NA No limit

NA=Not Applicable

a. Includes coal and wood.

b. Includes residual oil and process liquids.

c. Includes natural gas, process gas and refi nery gas.

d. Limited use is defi ned as having a federally enforceable annual average capacity factor equal to or less than 10%.
 Chapter 6 - Industrial and Commercial Boilers 71

SO2. Note, as discussed below, that state permits for 

industrial and commercial coal- and oil-fi red boilers can 

limit the sulfur content of fuels as an alternative means 

of limiting SO2 emissions. Table 6A.6, at the end of this 

chapter, highlights SO2 limits.

NOx. The San Joaquin Valley Unifi ed Air Pollution 

Control District (UAPCD) and the New Jersey Department 

of Environmental Protection (DEP) State of the Art 

(SOTA) Manual for Boilers and Process Heaters set the 

highest bar for NOx emissions from natural gas- and oilfi red industrial and commercial boilers. We provide more 

detail on their limits in the sections that follow. Also, 

the emissions limits imposed by the San Joaquin Valley 

UAPCD and the New Jersey SOTA cover units much 

smaller than the federal NSPS, which apply to units greater 

than 100 MMBtu/hr. Table 6A.7, at the end of this chapter, 

highlights NOx limits.

Additional Information on California and 

New Jersey Standards

The San Joaquin Valley UAPCD has set California’s most 

stringent limits for NOx emissions from industrial and 

commercial boilers, steam generators and process heaters. 

The rules apply to units with a heat input greater than 

0.075 MMBtu/hr, as described in Table 6A.8 at the end of 

this chapter.

In 2004, the New Jersey DEP updated its SOTA Manual 

for Boilers and Process Heaters referenced above. To do 

so, DEP reviewed recent permits issued in New Jersey and 

other states, state and federal regulations, BACT data from 

the Bay Area Air Quality Management District, BACT 

data from the California Air Resource Board, and data 

from EPA’s RACT/BACT/LAER Clearinghouse.

Table 6.10 shows New Jersey’s SOTA performance levels 

for NOx emissions from newly constructed, reconstructed 

and modifi ed natural gas- and distillate oil-fi red (note—

only distillate, and not residual oil) industrial and utility 

boilers and process heaters. New Jersey DEP notes that it 

evaluates boilers fi red with other fuels (e.g., coal or wood) 

on a case-by-case basis. 

The values in Table 6.10 are an order of magnitude more 

stringent than the NSPS for NOx emissions from natural 

gas- and distillate oil-fi red boilers. However, with the 

exception of distillate oil-fi red boilers greater than 75 

MMBtu/hr, they are not as stringent as the San Joaquin 

Valley UAPCD limits for natural gas-fi red boilers.

Emissions Standards for New and Existing 

EGU Boilers

In comments on proposed changes to the NSPS for EGUs 

and industrial and commercial boilers, STAPPA and 

ALAPCO take the position that EPA should apply the same 

limits to large industrial and commercial boilers (greater 

than or equal to 250 MMBtu/hr) as it applies to EGUs 

(STAPPA and ALAPCO, 2005). The Associations further 

advocated for more stringent SO2 and NOx emissions than 

EPA was proposing, and for the inclusion of both fi lterable 

and condensable PM in establishing PM limits. (For a 

summary of the proposed NSPS for EGUs, see Chapter 7, 

Electric Generating Units.)

Although there may be reasons in individual cases why 

EGU boiler limits are not feasible for industrial and 

commercial boilers, the EGU boiler standards suggest 

an appropriate starting point for consideration of limits 

for industrial and commercial boilers greater than 250 

MMBtu/hr and even those greater than 100 MMBtu/hr.

Regional CAIR “Plus” Approach

Another alternative for states to consider is supporting 

the Ozone Transport Commission (OTC) Multi-Pollutant 

Position, or similar programs that other regions may 

develop, aimed at achieving NOx, SO2 and mercury 

Table 6.10

New Jersey SOTA NOx Levels for Natural Gas- and Distillate Oil-Fired Boilers and Process 

Heaters

Fuel Capacity (MMBtu/hr) Controlled NOx Emissions 

Level (lb/MMBtu)

Control Technology

Natural gas 10 and <50 0.0350 LNB with FGR or ultra LNB

≥ 50 and <75 0.0200 LNB with FGR or ultra LNB

≥ 75 0.010 LNB with FGR and/or SCR

Distillate oil ≥ 10 and <75 0.0600 LNB with FGR

≥ 75 0.0300 LNB with FGR and SCR

Source: NJ DEP, 2004
72 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

emissions reductions from large industrial boilers, as well 

as from EGUs. (The EGU reductions would be deeper and 

come sooner than under CAIR.) The OTC’s approach is to 

use a regional partnership and a model rule to implement 

a program that goes beyond CAIR. The OTC would use 

the basic structure of CAIR to implement tighter emissions 

caps. The OTC aims to develop regional partnerships and 

a model rule in 2006, followed by a fi rst phase of controls 

in 2009 and a second phase in 2012 (InsideEPA, 2006). 

The support of states outside the OTC for such efforts 

could increase the likelihood of other regional programs. 

Fuel Sulfur Limits

In addition to the stack emissions limits described above, 

state and local agencies have opted in some cases to 

regulate the concentrations of sulfur in fuel, for example, 

by regulating the sulfur content of fuel oil.

In 2000, the Connecticut Department of Environmental 

Protection (DEP) adopted regulations limiting the sulfur 

content of fuel oil used by power plants (CT DEP, 2000). 

Effective January 1, 2002, affected units that combust 

liquid or gaseous fuels are subject to a fuel sulfur limit 

of 0.5 percent by weight. Effective January 1, 2003, 

the fuel sulfur limit is reduced to 0.3 percent by weight. 

Alternatively, an affected source can meet an average SO2

emissions rate of 0.33 lb/MMBtu. The DEP Commissioner 

can suspend the fuel sulfur limits in the event of a fuel 

supply emergency, in which case the Commissioner can 

require affected sources to offset excess emissions with 

SO2 allowances.

The New York State Department of Environmental 

Conservation regulates the sulfur content of oil and coal 

used by stationary combustion sources (NY DEC, 2005). 

The sulfur limits vary by area within the state. The lowest 

limits apply in New York City: (1) 0.30 percent sulfur by 

weight for residual oil, (2) 0.20 percent sulfur by weight 

for distillate oil and (3) 0.2 lb of sulfur per MMBtu 

gross heat content for solid fuels. As in Connecticut, the 

Commissioner has the authority to suspend the standards 

in the event of a supply shortage.

Limits on Back-Up Fuels

Over the past two decades, state and local offi cials have 

approved a large number of natural gas-fi red boilers. 

According to an offi cial in the Puget Sound Clean Air 

Agency, applicants frequently list oil as a back-up fuel. 

The offi cial noted that as the cost of natural gas increases, 

operators might switch from natural gas to oil (Van Slyke, 

2006). Since oil emissions limits are likely less stringent 

than natural gas emissions limits, this fuel switching 

negatively impacts air quality. As a result, it is important 

for state and local offi cials to evaluate the emissions 

impacts of both primary and back-up fuels during the 

review process.

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2003. www.epa.gov/ttn/catc/dir1/fsncr.pdf. (2003f)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Venturi 

Scrubber (EPA-452/F-03-017), July 2003. www.epa.gov/

ttn/catc/dir1/fventuri.pdf. (2003g)

U.S. Environmental Protection Agency (EPA). Air 

Pollution Control Technology Fact Sheet: Condensation 

Scrubber (EPA-452/F-03-010), July 2003. www.epa.gov/

ttn/catc/dir1/fcondnse.pdf. (2003h)

U.S. Environmental Protection Agency (EPA). “National 

Emission Standards for Hazardous Air Pollutants for 

Industrial, Commercial, and Industrial Boilers and Process 

Heaters; Final Rule,” Federal Register 69(176): 55218, 

September 13, 2004.

U.S. Environmental Protection Agency (EPA). 1999 

National Emission Inventory Final Version 3.0, obtained 

from EPA staff, October 2005. www.epa.gov/ttn/chief/net/

1999inventory.html. (2005a)

U.S. Environmental Protection Agency (EPA), Technology 

Transfer Network Clean Air Technology Center. RACT/

BACT/LAER Clearinghouse, accessed December 16, 

2005, from: http://cfpub.epa.gov/rblc/cfm/basicsearch.cfm. 

(2005b)

U.S. Environmental Protection Agency (EPA). “Standards 

of Performance for Electric Utility Steam Generating 

Units for Which Construction Is Commenced After 

September 18, 1978; Standards of Performance for 

Industrial-Commercial-Institutional Steam Generating 

Units; and Standards of Performance for Small IndustrialCommercial-Institutional Steam Generating Units; 

Proposed Rule,” Federal Register 70(38): 9705, February 

28, 2005. (2005c)

U.S. Environmental Protection Agency (EPA). Draft 

National Emissions Inventory 2002—PM Adjustment 

Memorandum, August 29, 2005. ftp://ftp.epa.gov/

EmisInventory/draftnei2002/point/documentation/pm_

adjustment_2002_nei.pdf. (2005d)

U.S. Environmental Protection Agency (EPA). “Standards 

of Performance for Electric Utility Steam Generating 

Units for Which Construction is Commenced After 

September 18, 1978; Standards of Performance for 

Industrial-Commercial-Institutional Steam Generating 

Units; and Standards of Performance for Small IndustrialCommercial-Institutional Steam Generating Units; Final 

Rule,” Federal Register 71(38): 9866, February 27, 2006.

Van Slyke, S, Puget Sound Clean Air Agency. Personal 

communication with M.J. Bradley & Associates, January 

5, 2006.

Washington State Department of Ecology (DEC). Hog 

Fuel Boiler RACT Determination (Publication # 03-02-

009), March 2005. www.ecy.wa.gov/pubs/0302009.pdf. 
 Chapter 6 - Industrial and Commercial Boilers 75

Table 6A.1

Industrial Boilers in the U.S. by Fuel Type and Capacitya,b

Primary 

Fuel

Capacity 

Range 

(MMBtu/

hr)

Average 

Capacity 

Factor 

(MMBtu/

hr)

Estimated 

Total 

Capacity 

(MMBtu/

hr)

% of 

Industrial 

Boiler 

Sector 

Capacityc

Percent of 

Capacity 

by Fuel

Number of 

Industrial 

Boilers

% of Total 

Industrial 

Boiler 

Sector 

Boilersc

% of 

Industrial 

Boilers by 

Fuel

Coal 0-10 3 358 <1% <1% 139 <1% 5%

10-100 53 63,231 3% 12% 1,188 3% 44%

100-250 172 133,877 7% 25% 778 2% 29%

>250 583 346,320 19% 64% 594 1% 22%

Subtotal - 201 543,786 29% 100% 2,699 6% 100%

Residual oil 0-10 3 1,908 <1% 1% 636 1% 25%

10-100 37 53,946 3% 28% 1,458 3% 57%

100-250 172 56,244 3% 29% 327 1% 13%

>250 547 80,956 4% 42% 148 <1% 6%

Subtotal - 75 193,054 10% 100% 2,569 6% 100%

Natural gas 0-10 3 61,467 3% 7% 20,462 48% 62%

10-100 33 355,554 19% 39% 10,738 25% 33%

100-250 164 201,240 11% 22% 1,224 3% 4%

>250 510 291,644 16% 32% 572 1% 2%

Subtotal - 28 909,905 49% 100% 32,996 77% 100%

Wood 0-10 5 1,018 <1% 1% 201 <1% 24%

10-100 31 13,868 1% 18% 450 1% 53%

100-250 177 17,851 1% 23% 101 <1% 12%

>250 500 45,988 2% 58% 92 <1% 11%

Subtotal - 93 78,725 4% 100% 844 2% 100%

Other >0 - 82,088 7% 3,592 9%

TOTAL - - 1,807,558 100% - 42,700 100% -

a. This table is based on data supplied in support of the Industrial/Commercial/Institutional Boiler and Process Heaters National Emission 

Standards for Hazardous Air Pollutants (EPA, 2004). Eastern Research Group (ERG) used the Industrial Combustion Coordinated 

Rulemaking (ICCR) Inventory and Survey data to populate a new database of facilities separated by fuel type, capacity and control 

technology.

b. The database used as a source for this data combined different fuel types to fi t into general categories. For example, the “natural gas” 

fuel in this table includes other gases such as landfi ll gas, blast furnace gas, propane and butane. Based on an independent industrial 

boiler population analysis (EEA, 2005), it appears that the vast majority of the boilers listed as “natural gas” in this table are natural gasfi red boilers.

c. Smaller sectors (e.g., distillate oil) are not included in this table, but are included in the total used to calculate percent by sector. As a 

result, the percent calculations do not add to 100%. 

Source: Alvis, 2002
76 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 6A.2

Cost-Effectiveness and Control-Effectiveness of Combustion and Post-Combustion NOx

Control Options for Retrofi t on Industrial Boilers

Fuel Technology

NOx

Reduction 

(%)

Capacity 

Factor (%)

Cost-Effectiveness ($/Ton NOx)

100 MMBtu/hr 250 MMBtu/hr 1,000 MMBtu/hr

Subbituminous 

coal

LNB 51 14 3,033 2,304 1,520

50 849 645 426

83 512 389 256

LNB/OFA 65 14 3,428 2,608 1,727

50 972 743 496

83 593 454 306

Bituminous 

coal

LNB/OFA 51 14 4,358 3,317 2,197

50 1,239 947 634

83 757 581 392

Coal SCR 80 14 7,262 5,924 4,481

50 2,141 1,766 1,359

83 1,349 1,123 876

SNCR 40 14 4,970 4,015 2,962

50 2,073 1,814 1,510

83 1,625 1,473 1,285

Oil LNB/OFA (0.5 lb/

MMBtu inlet NOx)

30 10 5,260 3,986 2,630

50 1,052 797 526

86 612 464 306

LNB/OFA/FGR (0.5 

lb/MMBtu inlet NOx)

50 10 4,973 3,790 2,505

50 1,028 791 533

86 615 477 326

LNB/OFA/FGR 

(0.36 lb/MMBtu inlet 

NOx)

30 10 11,303 8,613 5,694

50 2,337 1,798 1,210

86 1,399 1,085 741

SCR (0.36 lb/

MMBtu inlet NOx)

80 5 25,838 20,113 14,601

50 2,767 2,178 1,622

86 1,694 1,343 1,017

SCR (0.5 lb/MMBtu 

inlet NOx)

80 5 18,544 14,443 10,458

50 2,014 1,595 1,191

86 1,245 997 760

SNCR (0.5 lb/

MMBtu inlet NOx)

40 10 7,399 5,892 4,271

50 2,367 2,070 1,749

86 1,840 1,670 1,485

SNCR (0.36 lb/

MMBtu inlet NOx)

40 10 9,842 7,753 5,497

50 2,853 2,444 1,995

86 2,123 1,889 1,628
 Chapter 6 - Industrial and Commercial Boilers 77

Table 6A.2, continued

Cost-Effectiveness and Control-Effectiveness of Combustion and Post-Combustion NOx

Control Options for Retrofi t on Industrial Boilers

Fuel Technology

NOx

Reduction 

(%)

Capacity 

Factor (%)

Cost-Effectiveness ($/Ton NOx)

100 MMBtu/hr 250 MMBtu/hr 1,000 MMBtu/hr

Natural gas LNB/OFA 60 5 10,521 7,973 5,260

50 1,052 797 526

94 559 424 280

LNB/OFA/FGR 80 5 12,374 9,415 6,204

50 1,278 981 656

94 700 543 368

SCR 80 5 26,859 21,095 14,815

50 2,933 2,330 1,670

94 1,689 1,354 986

SNCR 40 5 27,105 20,870 14,165

50 3,735 3,116 2,452

94 2,521 2,193 1,842

Source: Khan, 2003a
78 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 6A.3

NSPS for Industrial and Commercial Boilers (40 CFR §§60.40b, et seq. (subpart Db), and 40 

CFR §§60.40c, et seq. (subpart Dc))

Fuel 

Type

Capacity 

(MMBtu/hr) PM Limit SO2 Limit NOx Limit

Coal 10 - 30 NA 90% reduction from 

potential SO2 emissions 

levels and SO2

emissions rate less 

than or equal to 1.2 

lb/MMBtu (assuming 

100% coal)a

NA

Coal 30 - 100 0.051 lb/MMBtu (assuming 100% 

coal); no more than 20% opacity 

(6-minute average)

Coalb >100 0.051 lb/MMBtu (assuming 100% 

coal)

90% reduction from 

potential SO2 emissions 

levels or SO2 emissions 

rate less than or 

equal to 1.2 lb/MMBtu 

(assuming 100% coal)

0.5-0.8 lb/MMBtu depending on 

coal and boiler type

0.3 lb/MMBtu for facilities 

commencing construction or 

reconstruction after July 9, 1997c

Residual 

oil

10 - 100 No more than 20% opacity (6-

minute average)

0.50 lb/MMBtu or 

combust oil 0.5% sulfur 

by weight or less

NA

Residual 

oil

>100 0.1 lb/MMBtu 90% reduction from 

potential SO2 emissions 

levels or SO2 emissions 

rate less than or 

equal to 0.8 lb/MMBtu 

(assuming 100% oil)

0.30 lb/MMBtu (low heat release), 

0.40 lb/MMBtu (high heat release)d

0.3 lb/MMBtu for facilities 

commencing construction or 

reconstruction after July 9, 1997

Natural 

gas

10 - 100 NA NA NA

Natural 

gas

>100 NA NA 0.10 lb/MMBtu (low heat release), 

0.40 (high heat release) 

0.3 lb/MMBtu for facilities 

commencing construction or 

reconstruction after July 9, 1997e

Wood >30 0.1 lb/MMBtu, nothing greater 

than 20% opacity (6-minute 

average, capacity factor greater 

than 30%)

NA NA

Wood >100 0.1 lb/MMBtu (capacity factor 

greater than 30%)

NA NA

a. Alternate SO2 limits exist for facilities using fl uidized bed combustion (with coal) or an emerging technology for the control of SO2

emissions.

b. There are exceptions to standards for coal- and oil-fi red units greater than 100 MMBtu/hr that commenced construction, reconstruction 

or modifi cation after June 19, 1984 but on or before June 19, 1986. There are further exceptions to the PM limits for coal-fi red units that 

commenced construction after June 19, 1984 but on or before November 25, 1986.

c. The 1997 limits for coal-, residual oil- and natural gas-fi red boilers greater than 100 MMBtu/hr include exceptions for affected facilities 

with annual capacity factors for coal, residual oil or natural gas of 10% or less.

d. The heat release points are defi ned by fuel and steam generating unit type in 40 CFR §60.44b.

e. If a natural gas-fi red boiler has a low heat release rate and combusts natural gas in excess of 30% of the heat input, the limit is 

determined by an equation in 40 CFR §60.44b.
 Chapter 6 - Industrial and Commercial Boilers 79

Table 6A.3-1

NSPS for Industrial and Commercial Boilers Constructed, Reconstructed or Modifi ed after 

February 28, 2005

Fuel Type

Capacity 

(MMBtu/hr) PM Limita SO2 Limit

Coal, oil, 

natural gas, wood

30–100 0.03 lb/MMBtu No change (see Table 6A.3)

>100 0.03 lb/MMBtu 0.20 lb/MMBtub

a. Modifi ed wood-fi red units greater than 30 MMBtu/hr and less than or equal to 250 MMBtu/hr have a limit of 0.10 lb/MMBtu. Modifi ed 

units greater than 250 MMBtu/hr have a limit of 0.085 lb/MMBtu.

b. Units burning only oil that contains no more than 0.3 percent sulfur by weight or any idividual fuel that, when combusted without SO2

emissions control, have an SO2 emissions rate equal to or less than 0.32 lb/MMBtu, are exempt from other SO2 emissions limits.

Source: EPA, 2006
80 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 6A.4

Recent BACT Determinations for Industrial and Commercial Boilers Posted in the RACT/

BACT/LAER Clearinghouse

Fuel 

(Basis)

Throughput 

MMBtu/hr

RBLC 

IDa

Permit 

Date 

(Type)

PM SOx NOx

Limit Control Limit Control Limit Control

Natural 

gas 

(BACT/

PSD)

80 WI02071/2004 

(New)

0.0075 

lb/MMBtu

Good 

combustion

ND 0.04 lb/

MMBtu

LNB

Lignite 

(BACT/

PSD)

250 ND00208/2004 

(New)

0.048 

lb/MMBtu 

(PM10, 

0.02 lb/

MMBtu)

Fabric Filter 0.09 lb/

MMBtu

FGD 0.1 lb/

MMBtu

SNCR

Wood 

(BACT/

PSD)

230 MN00586/2005 

(New)

PM10, 

0.025 lb/

MMBtu

ESP ND 0.15 lb/

MMBtu

SNCR

Oil 

(BACT/

PSD)

50.2 WA031311/2003 

(New)

0.02 lb/

MMBtu

Reduced 

Hours

ND 0.09 lb/

MMBtu

LNB, FGR, 

Atomization

Natural 

gas 

(BACT/

PSD)

34 IN010811/2003 

(Modifi ed)

PM10, 

0.0076 

lb/MMBtu

ND 0.0006 

lb/

MMBtu

ND ND

Natural 

gas 

(BACT/

PSD)

22 AR00777/2004 

(New)

PM10, 

0.0076 

lb/MMBtu

ND 0.0006 

lb/

MMBtu

ND ND

Oil 

(BACT/

PSD)

94 NJ00463/1996 

(Modifi ed)

ND 0.32 lb/

MMBtu

ND 0.28 lb/

MMBtu

LNB

Coal 

(BACT/

PSD)

249 NC0092

5/2001 

(Modifi ed)

0.16 lb/

MMBtu

Multicyclone 

and wet 

scrubber

0.8 lb/

MMBtu

Wet 

scrubber

0.4 lb/

MMBtu

Good 

combustion

Coal 

(BACT/

PSD)

238 OH02415/2004 

(Modifi ed)

PM10, 

0.031 lb/

MMBtu

Fabric Filter 1.6 lb/

MMBtu

No 

Control

0.7 lb/

MMBtu

OFA

Coal 

(BACT/

PSD)

146.7 VA02678/2001 

(New)

PM10, 0.02 

lb/MMBtu

Fabric Filter 1.6 lb/

MMBtu

FGD 0.25 lb/

MMBtu

Low excess 

air, staged 

combustion

Residual 

oil (BACT/

PSD)

150 VA02783/2003 

(Modifi ed)

PM10, 0.05 

lb/MMBtu

Good 

combustion 

practices

0.52 lb/

MMBtu

Lowsulfur 

fuel

0.4 lb/

MMBtu

LNB

ND = No Data

a. RBLC ID = RACT/BACT/LAER Clearinghouse identifi cation number.

Source: EPA, 2005b
 Chapter 6 - Industrial and Commercial Boilers 81

Table 6A.5

Summary of Most Stringent PM Limits for New and Existing Industrial and Commercial 

Boilers in the U.S.

Fuel Type

Boiler Size 

(MMBtu/hr) Limit (lb/MMBtu) Source a

Coal <10 0.025 (New) Federal MACT

10-250 0.025 (New), 0.07 

(Existing)

Federal MACT

>250 0.015 (New), 0.07 

(Existing)

New: BACT determinations for coal-fi red EGUs (WY-0057, PR0007, IA-0051); Existing: Federal MACT

Residual oil 0.075-10 0.03 (New) Federal MACT

10-100 0.02 (New) Washington State BACT determination (WA-0313)

100-250 0.03 (New) Federal MACT

>250 0.015 (New) BACT determinations for coal-fi red EGUs (WY-0057, PR-0007, 

IA-0051)

Natural gas 0.4-5.0 0.007 (New) South Coast AQMD BACT Determination

>5.0 0.007 (New); 

0.0076 (Existing)

New: South Coast AQMD BACT determination; Existing: Indiana 

BACT determination (IN-0108)

Wood <10 0.025 (New) Federal MACT

10-250 0.025 (New) Federal MACT

>250 0.015 (New) BACT determinations for coal-fi red EGUs (WY-0057, PR-0007, 

IA-0051)

a. RBLC ID (RACT/BACT/LAER Clearinghouse identifi cation number) included where applicable.
82 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 6A.6

Summary of Most Stringent SO2 Limits for New and Existing Industrial and Commercial 

Boilers in the U.S.

Fuel Type

Boiler Size

 (MMBtu/hr) Limit (lb/MMBtu) Sourcea

Coal 10-100 1.2 (New) Federal NSPS

100-250 0.16 (New), 

0.8 (Existing)

New: Virginia BACT determination (VA-0267)a; Existing: North 

Carolina BACT determination (NC-0092)

>250 0.10 (New) BACT determinations for coal-fi red EGUs (IA-0067, WY-0057)

Residual oil 10-100 0.32 (New, Existing) New Jersey BACT determination (NJ-0046)

100-250 0.8 (New, Existing) New: Federal NSPS; Existing: North Carolina BACT 

determination (NC-0092)

>250 0.8 (New) Federal NSPS

Natural gas >5.0 0.0006 (New, 

Existing)

New: Arkansas BACT determination (AR-0077); Existing: Indiana 

BACT determination (IN-0108)

Wood >250 0.10 (New) BACT determinations for coal-fi red EGUs (IA-0067, WY-0057)

a. RBLC ID (RACT/BACT/LAER Clearinghouse identifi cation number) included where applicable.
 Chapter 6 - Industrial and Commercial Boilers 83

Table 6A.7

Summary of Most Stringent NOx Limits for New and Existing Industrial and Commercial 

Boilers in the U.S.

Fuel Type

Boiler Size

 (MMBtu/hr) Limit (lb/MMBtu) Source a

Coal 100-250 0.3 (New), 

0.4 (Existing)

New: Federal NSPS; Existing: North Carolina BACT 

determination (NC-0092)

 >250 0.07-0.08 (New) BACT determinations for coal-fi red EGUs (IA-0067, KS0026, WY-0057, MO-0050, IA-0051)

Residual oil 0.075-0.4 0.093 (New, Existing) San Joaquin Valley UAPCD

 0.4-2.0 0.036 (New, Existing) San Joaquin Valley UAPCD

2.0-250 0.052 (New, Existing) San Joaquin Valley UAPCD

 >250 0.03 (New), 0.052 

(Existing)

New: New Jersey SOTA; Existing: San Joaquin Valley 

UAPCD

Natural gas 0.075-0.4 0.093 (New, Existing) San Joaquin Valley UAPCD

 0.4-5.0 0.036 (New, Existing) San Joaquin Valley UAPCD

 >5.0 0.007 (New, Existing) San Joaquin Valley UAPCD

Wood 100-250 0.15 (New) Minnesota BACT determination for wood-fi red EGU boiler 

(MN-0058)

>250 0.07-0.08 (New) BACT determinations for coal-fi red EGUs (IA-0067, KS0026, WY-0057, MO-0050, IA-0051)

a. RBLC ID (RACT/BACT/LAER Clearinghouse identifi cation number) included where applicable.
84 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 6A.8

San Joaquin Valley UAPCD NOx Levels for Gaseous Fuel- and Liquid-Fired Boilers, Steam 

Generators and Process Heaters

Fuela

Capacity 

(MMBtu/hr) Units Covered

Controlled NOx Emissions Level 

(lb/MMBtu)

Gaseous fuel ≥ 0.075 and 

≤ 0.4

All units supplied, sold, installed or 

solicited for installation on and after 

January 1, 2007

0.093 lb/MMBtu

>0.4 and <2.0 All units supplied, sold, installed or 

solicited for installation on and after 

January 1, 2007

0.036 lb/MMBtu

≥ 2.0 and ≤ 5.0 All units; owners must register units by 

January 1, 2008

0.036 lb/MMBtu (30 ppmv)

>5 MMBtu/hr Units with a rated heat input equal to or 

less than 20.0 MMBtu/hour

Standard option: 0.018 lb/MMBtu (15 

ppmv); enhanced option: 0.011 lb/

MMBtu (9 ppmv)b

>5 MMBtu/hr Units with a rated heat input greater 

than 20.0 MMBtu/hour

Standard option: 0.011 lb/MMBtu 

(9ppmv); enhanced option: 0.007 lb/

MMBtu (6 ppmv)

Liquid fuel ≥ 0.075 and 

≤ 0.4

All units supplied, sold, installed or 

solicited for installation on and after 

January 1, 2007

0.093 lb/MMBtu

>0.4 and <2.0 All units supplied, sold, installed or 

solicited for installation on and after 

January 1, 2007

0.036 lb/MMBtu

≥ 2.0 and ≤ 5.0 All units, owners must register units by 

January 1, 2008

0.052 lb/MMBtu (40 ppmv)

>5 MMBtu/hr All units, must be in full compliance by 

December 1, 2008

0.052 lb/MMBtu (40 ppmv)

All limits are at 3% stack gas oxygen by volume.

ppmv = parts per million on dry volume basis.

a. The rule specifi es different limits for oilfi eld steam generators; refi nery units with a rated heat input greater than 5 MMBtu/hr; loadfollowing units; units limited by a permit to operate to an annual heat input of 9 billion Btu/year to 30 billion Btu/year; and units in which the 

rated heat input of each burner is less than or equal to 5 MMBtu/hr but the total rated heat input of all the burners in a unit is great than 5 

MMBtu/hr.

b. Under the standard option, qualifying units must be in full compliance by June 1, 2007. Under the enhanced option, units must be in 

compliance by December 1, 2008.

Source: San Joaquin Valley UAPCD, 2005a, 2005b, 2005c
86 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Electric generating units (EGUs) in the U.S. produced 

3.953 trillion kilowatt-hours (trillion kWh) of electricity 

in 2004.1 Sources that combust coal, oil or natural gas 

provided 70 percent of that amount (EIA, 2005a). EGUs 

that use combustion processes include large steam boiler/

generators, combustion turbines and stationary internal 

combustion (IC) engines. Combustion-based EGUs 

account for 39 percent of total fossil fuel consumption 

in the U.S. and are the largest industrial point source 

contributors of fi ne particulate (PM2.5), sulfur dioxide 

(SO2) and nitrogen oxides (NOx) emissions (EIA, 2005b; 

EPA, 2005a).

The size, technology, fuel and operating characteristics 

of EGUs are largely dependent on the purpose they are 

designed to serve in meeting electricity demand. Large 

pulverized coal boilers, for example, are designed 

primarily to operate as base load generating facilities run 

at high capacity factors. (Capacity factor is a measure of 

plant utilization; these plants run at capacity factors of 

70–90 percent.) Simple cycle combustion turbines and 

IC engines, on the other hand, can be quickly ramped up 

and down to meet changing electricity demand and are 

generally operated as peaking facilities. The average size 

of a coal-fi red boiler in the U.S. is over 200 megawatts 

(MW) while the average size of a simple cycle natural gas 

1. A kWh is a unit of energy equivalent to one kilowatt of power expended over one hour. A 100-watt bulb burning for ten hours will use 

one kilowatt hour of energy.

turbine is 50 MW, and that of an IC engine is only about 2 

MW (EIA, 2003). 

As discussed below, large coal-fi red boilers are responsible 

for the vast majority of emissions from the electric 

generating sector and are subject to a multitude of existing 

federal and state programs to reduce emissions. Peaking 

facilities tend to produce signifi cantly less total air 

emissions, and in some cases may not be subject to the 

same regulations or pollution control requirements because 

of their smaller capacity. 

This chapter discusses PM2.5, SO2 and NOx emissions 

from EGUs, with an emphasis on technical and policy 

approaches for reducing emissions. The discussion 

Chapter 7

Electric Generating Units
 Chapter 7 - Electric Generating Units 87

highlights the importance of generator technology and fuel 

choice in determining direct PM2.5 and PM2.5-precursor 

emissions as well as the control technology options 

available for different types of EGUs. The chapter includes 

discussion of the emissions, current regulatory treatment 

and control options for large pulverized coal and other 

steam boilers, combustion turbines and IC engines used at 

electric generating facilities. We conclude by outlining a 

series of measures that state and local governments could 

pursue to achieve further emissions reductions. 

The discussion provides a general review of control 

technology options, but it does not duplicate the more 

detailed discussion of emissions control opportunities for 

EGU boilers provided in Chapter 5, Boiler Technologies.

Sector Profi le

The electric power sector in the U.S. is based on a familiar 

model, one that is replicated throughout the world. Large 

central power stations, often in remote locations, spin 

generators to feed a network of high-voltage transmission 

lines. These carefully synchronized generators are 

generally powered by coal, natural gas, oil, water or nuclear 

fi ssion. The electricity pulsing through the transmission 

grid feeds a system of low-voltage distribution lines, which 

connect to homes and businesses. Turning on a reading 

lamp or computer connects the appliance to this network 

of wires, drawing electricity from the grid. Power plant 

operators are continually responding to these changes 

in the system, increasing or decreasing supply to match 

demand in a carefully orchestrated exercise managed by a 

central authority or dispatcher.

There are more than 17,000 EGUs in the U.S., with a 

combined generating capacity of about 950 gigawatts 

(GW). Of this capacity, 78 percent (over 700 GW) is 

fueled by the combustion of fossil fuels, including 313 GW 

of coal, 59 GW of oil and 355 GW of natural gas (EIA, 

2003). In 2004, the industry generated almost four trillion 

kWh of electricity, including 2.78 trillion kWh (70 percent) 

from fossil fuel combustion (EIA, 2005a). Figure 7.1 

illustrates U.S. generating capacity and generation in 2004 

by fuel type. 

As Figure 7.1 illustrates, the share of generating capacity 

and generation are different across the different fuel types. 

For example, coal-fi red power plants produced 50 percent 

of U.S. electricity in 2004, while accounting for only about 

34 percent of capacity. In contrast, natural gas-fi red power 

plants, which account for about 38 percent of capacity, 

generated less than 20 percent of the country’s electricity. 

This dichotomy is refl ective of the higher capacity 

utilization of coal-fi red power plants, primarily operated 

to serve base load, as compared to natural gas facilities, 

which tend to operate as load following or peaking units. 

The average capacity factor across all coal-fi red power 

plants in 2003 was 72 percent, versus 21 percent for natural 

gas and 20 percent for oil-fueled sources (EIA, 2003; EIA, 

2004a).

Different technologies are used to generate electricity, 

depending on the energy source. Table 7.1 shows that 

steam boilers are fueled by a variety of energy sources, but 

that coal accounts for the largest segment. Natural gas, 

on the other hand, is the dominant fuel used for turbines 

operating in a combined cycle mode (i.e., that include 

a heat recovery steam generator to provide a second 

generation cycle) and for simple cycle turbines without 

Fig. 7.1 U.S. Generating Capacity and Generation by Fuel Type

Capacity Generation Source: EIA,2005a
88 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

a steam cycle.2 Oil (which includes diesel fuel) and to 

a lesser extent natural gas are used to fuel stationary IC 

engines (e.g., piston and diesel engines).

Emissions

The electric power sector is the single largest source of 

PM2.5, SO2 and NOx emissions among all the major point 

source categories. Nationwide, EGUs account for nearly 

70 percent of SO2 emissions, more than 20 percent of 

NOx emissions and almost 10 percent of PM2.5 emissions. 

Excluding fugitive dust, forest wildfi res and agricultural 

fi res (i.e., the miscellaneous categories), EGUs account for 

more than 20 percent of PM2.5 emissions nationwide (EPA, 

2005b).

Within the EGU sector, coal-fi red power plants account for 

the vast majority of PM2.5, SO2 and NOx emissions (EPA, 

2005b). Table 7.2 presents 2002 EGU emissions by fuel 

type. In 2002, coal-fi red facilities were responsible for 

92, 95 and 87 percent of EGU emissions of PM2.5, SO2 and 

NOx, respectively. 

Coal combustion dominates EGU emissions because 

it accounts for 70 percent of fossil fuel-fi red electric 

generation and because coal-fi red facilities tend to have 

relatively high emissions rates, particularly compared 

to facilities fi ring natural gas. The higher emissions 

rates stem from the relatively high concentrations of 

2. The combined cycle turbines in Table 7.1 operated on coal are two 

integrated gasifi cation combined cycle (IGCC) power plants (in Wabash, 

Indiana and Polk County, Florida) that use gasifi cation technology to 

convert coal into synthesis gas that can be used to fuel a combined cycle 

power block.

sulfur, nitrogen and ash in coal, which is converted to 

PM, SO2 and NOx during combustion. The formation 

of these pollutants as a result of coal, oil and natural gas 

combustion is described briefl y below.

PM. Uncontrolled PM emissions from coal- and oil-fi red 

boilers include the ash from combustion of the fuel and the 

unburned carbon resulting from incomplete combustion. 

In pulverized coal boilers, the combustion process is 

almost complete, so the majority of the PM emitted is 

composed of inorganic ash residues (EPA, 1998a). The 

average ash content of bituminous coal consumed by the 

electric power industry in 2003 was 10.1 percent, while the 

average ash content of subbituminous coal was 6.4 percent 

and of lignite 13.3 percent (EIA, 2004b). For fuel oil, PM 

emissions depend predominantly on the grade of fuel. 

Combustion of lighter distillate oils results in signifi cantly 

less PM formation than does combustion of heavier 

residual oils. Because natural gas is a gaseous fuel, PM 

emissions resulting from its combustion are typically very 

low (EPA, 1995).

NOx. NOx formation results from the thermal fi xation of 

atmospheric nitrogen in the combustion fl ame (“thermal 

NOx”) and from oxidation of nitrogen bound in the fuel 

(“fuel NOx”). Bituminous and subbituminous coals usually 

contain from 0.5 to 2 percent nitrogen by weight. Fuel 

nitrogen can account for as much as 80 percent of total 

NOx emissions from coal combustion (EPA, 1995). Fuel 

NOx is also the more important NOx-forming mechanism 

in residual oil boilers, but thermal NOx is the dominant 

NOx-forming mechanism in units fi ring distillate oils and 

the only mechanism in natural gas combustion systems 

(EPA, 1995).

Table 7.1

U.S. Generating Capacity by Fuel Type and Prime Mover Technology (2003, Megawatts)

Prime Mover Technology

Total

Steam 

Boilers

Combined 

Cycle 

Turbines

Simple 

Cycle 

Turbines

HydroelectricIC 

Engine

Wind/

Solar/ 

Fuel Cell

Pumped 

Storage Other

Fuel Type

Coal 312,453 566 313,019

Natural gas 98,826 145,674 108,770 2,102 119 355,492

Nuclear 99,209 99,209

Oil 34,017 1,396 18,161 4,913 22 58,509

Other 7,908 247 2,430 8 59 10,651

Renewable 5,449 110 152 585 6,004 49 12,351

Water 78,694 20,522 99,216

 Total 557,863 147,993 129,513 78,694 7,608 6,004 20,522 249 948,446

Source: EIA, 2003
 Chapter 7 - Electric Generating Units 89

SO2. SO2 compounds form when sulfur in coal or oil is 

oxidized during combustion. The average sulfur content 

of bituminous coal delivered to EGUs in 2003 was 1.49 

percent, while the average sulfur content of subbituminous 

coal was 0.37 percent and of lignite 0.94 percent (EIA, 

2004b). Fuel oil sulfur content depends on grade, but is 

generally less than one percent. Natural gas has virtually 

no sulfur and therefore produces almost no SO2 when 

combusted. About 95 percent of the sulfur present in 

fossil fuels is emitted as gaseous SO2 when combusted 

(EPA, 1995).

Table 7.3 shows the emissions rates of uncontrolled EGU 

pulverized coal boilers, along with those of oil- and natural 

gas-fi red combustion turbines and oil- and natural gasfi red IC engines. It should be noted that the uncontrolled 

fuel input emissions rates of natural gas-fi red combined 

cycle power plants are the same as the uncontrolled 

emissions rates shown for simple cycle turbines because 

the same combustion occurs in both systems. However, on 

an output basis (e.g., emissions in pounds per megawatthour—lb/MWh), combined cycle systems have lower 

emissions rates due to the improved effi ciency attributable 

to the heat recovery steam cycle. 

The uncontrolled emissions rates shown in Table 7.3 are 

higher than the emissions rates of many EGUs operating 

today because most facilities have some form of PM, 

SO2 or NOx emissions control. As a point of reference, 

the average emissions rates for NOx and SO2 across all 

coal-fi red EGUs in the U.S. in 2002 were 0.40 pounds 

per million British thermal unit (lb/MMBtu) and 0.94 lb/

MMBtu, respectively (NRDC, 2004).

Emissions Control Opportunities

Numerous options are available for reducing PM2.5 and 

PM2.5-precursor emissions from EGUs. In general, the 

options fall into three basic categories: (1) fuel switching 

to lower emitting fuels; (2) control technologies (including 

combustion and post-combustion controls) for both 

new and existing facilities; and (3) reliance on lower 

emitting (including non-emitting) forms of electric power 

generation. In the discussion that follows, we provide an 

overview of the control technologies available to the EGU 

sector, focusing fi rst on boiler control technologies. We 

discuss combustion turbines and IC engines separately. A 

more detailed discussion of the control options for coal-, 

oil-, natural gas- and wood-fi red boilers is contained in 

Chapter 5, Boiler Technologies.

A note on cost-effectiveness: Throughout, we report 

the cost-effectiveness of individual control options applied 

to a specifi c type of facility, such as the cost per ton of 

reducing SO2 emissions from a coal-fi red power plant. 

However, in many cases emissions of NOx and SO2 (though 

not PM2.5) from fossil-fi red power plants are regulated 

under a cap-and-trade system, and the costs of control are 

Table 7.2

EGU Emissions by Fuel Type (2002)

Fuel Type PM2.5 SO2 NOx

Thousand 

Tons/Year

Percent 

of Sector 

Emissions

Thousand 

Tons/Year

Percent 

of Sector 

Emissions

Thousand 

Tons/Year

Percent 

of Sector 

Emissions

Coal 535 92% 9,738 95% 4,097 87%

bituminous 419 72% 7,317 71% 2,635 56%

subbituminous 95 16% 1,949 19% 1,296 28%

anthracite & lignite 22 4% 465 5% 163 3%

Oil 13 2% 343 3% 130 3%

residual 12 2% 330 3% 121 3%

distillate 1 0% 13 0% 8 0%

Natural Gas 11 2% 8 0% 270 6%

Other 8 1% 191 2% 50 1%

Internal Combustion 14 2% 13 0% 152 3%

Total 582 100 10,293 100 4,700 100

Source: EPA, 2005b
90 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

determined by many factors, including fuel prices, fuel 

transportation costs, pollution control system costs and 

other factors. In theory, the price of allowances under a 

cap-and-trade program should refl ect the marginal cost of 

compliance, or the cost of reducing one additional ton of 

SO2 or NOx. As a result, the allowance market provides 

a measure of cost-effectiveness at the prevailing cap level. 

The cost-effectiveness of a single control option is less 

informative.

Fuel Switching

Fuel switching can be an effective strategy for reducing 

PM2.5, SO2 and NOx emissions. For example, switching 

from a high-sulfur (bituminous) coal to a low-sulfur 

(subbituminous) coal can reduce a plant’s SO2 emissions 

by more than 70 percent. Fuel blending has also been 

widely used in order to control SO2 emissions. This has 

been one of the industry’s key strategies for complying 

with the federal Acid Rain program (Title IV of the Clean 

Air Act), as evidenced by the sector’s growing reliance 

on low-sulfur coal supplies over the past decade (USGS, 

2001). Switching from coal to natural gas produces an 

even more dramatic result, virtually eliminating a plant’s 

SO2 and direct PM2.5 emissions.

Fuel switching, however, is not without its complications. 

The feasibility of fuel switching will depend in part on the 

characteristics of the plant and the particular type of fuel 

change at issue. Many plants will be able to switch from 

high-sulfur to low-sulfur bituminous coal without serious 

diffi culty, but switching from bituminous to subbituminous 

coal may present greater challenges and costs. In some 

instances, fuel switching will require signifi cant investment 

and modifi cations to an existing plant. Switching to a 

lower-sulfur coal can affect coal handling systems, boiler 

performance, PM control-effectiveness and ash handling 

systems (Rastogi, 2001; Rubin, 2001). Rail lines may also 

limit access to lower-sulfur coals.

Switching from oil to gas is relatively easy and many plants 

already have dual oil- and gas-fi ring capacity. Going from 

a higher- to a lower-sulfur residual oil or from residual 

to distillate oil is also possible, although issues related 

to differences in the viscosity of the fuel may have to be 

addressed.

The availability of fuel switching as a control strategy 

for a specifi c power plant will also depend heavily on the 

location of the facility. For example, a power plant may 

be unable to access lower-sulfur coal supplies due to its 

Table 7.3

Typical Uncontrolled Emissions Rates for EGU Facilities

Technolgy & Fuel PM2.5 SO2 NOx

lb/MMBtu lb/MWh lb/MMBtu lb/MWh lb/MMBtu lb/MWh

Pulverized coal bituminous (3% sulfur)a 0.3 2.5 4.8 47.5 0.9 9.2

Pulverized coal bituminous (1.5% sulfur)a 0.3 2.5 2.4 23.6 0.9 9.2

Pulverized coal subbituminous (0.35% sulfur)b 0.2 2.1 0.6 6.5 0.7 6.7

Natural gas combined cyclec Negligible Negligible 0.32 2.2

Simple cycle turbine natural gasd Negligible Negligible 0.32 3.1

Simple cycle combustion turbine distillate oil 0.004 0.04 0.03 0.3 0.88 8.6

Internal combustion engine natural gase Negligible Negligible 2.7 45.9

Internal combustion engine diesel 

(high-sulfur diesel—5%)e

0.1 1.70 0.51 8.6 3.2 54.4

Internal combustion engine diesel 

(low-sulfur diesel—0.5%)e

0.1 1.70 0.05 0.9 3.2 54.4

a. Assumes coal ash content of 10%, 24 MMBtu/ton coal heating value and 10,000 Btu/kWh heat rate. Rates based on uncontrolled drybottom, wall-fi red boiler.

b. Assumes coal ash content of 6.4%, 18 MMBtu/ton coal heat content and 10,000 Btu/kWh heat rate. Rates based on uncontrolled drybottom, wall-fi red boiler.

c. Assumes heat rate of 7,000 Btu/kWh, no steam injection or other controls.

d. Assumes heat rate of 9,800 Btu/kWh, no steam injection or other controls.

e. Assumes heat rate of 17,000 Btu/kWh.

Source: EPA, 1996, 1998a, 2000
 Chapter 7 - Electric Generating Units 91

location, or it may lack access to a natural gas pipeline. 

Many low-sulfur coals actually cost less than high-sulfur 

coals, even accounting for the fact that the high-sulfur 

coals may be higher rank (i.e., the cost of the low-sulfur 

coal can be less per unit of heat input). But because these 

fuels frequently have a lower heat content, switching to a 

low-sulfur coal may reduce boiler output, requiring more 

fuel consumption per unit of electricity output. Fuel prices 

may also limit the availability of lower emitting fuels. 

Since transportation costs make up a large fraction of the 

delivered price of coal, the prices paid for low-sulfur coal 

varies widely among power plants. Finally, natural gas is 

signifi cantly more expensive than coal.

As an example of the cost of fuel switching, in 2002 

Manitoba Hydro converted its 132 MW Selkirk plant 

from coal to natural gas after 40 years of using coal for 

electricity production. The project required a $30 million 

capital investment, including the installation of low-NOx

burners (LNBs), fuel control equipment, a burner safety 

system, the replacement of boiler pressure parts and the 

construction of 35 miles of high-pressure gas transmission 

pipeline (University of Manitoba, 2005). In addition to 

these capital expenses, the company estimates that the 

plant will cost an additional $10 million per year to operate 

because of higher fuel costs and lost revenue opportunities 

stemming from these higher fuel costs. (The actual fi gure 

may be higher in light of recent fuel prices.) The emissions 

benefi ts of the project have been dramatic, as summarized 

in Table 7.4. 

Fuel switching options for boilers are discussed in more 

detail in Chapter 5, Boiler Technologies.

Fuel Cleaning

There are several options for treating fuels prior to 

combustion that will reduce emissions at the power plant. 

In particular, coal washing is widely practiced in the U.S. 

to remove impurities (sulfur and ash) and to increase the 

coal’s heating value.

Coal washing removes varying degrees of sulfur and 

ash, depending on the type of coal and the cleaning 

process. There are two forms of sulfur in coal. The 

fi rst is an inorganic form called “pyrite.” The second is 

organic sulfur, which is chemically bound in the molecular 

structure of coal itself. Conventional coal washing 

removes only inorganic sulfur and nitrogen—physical 

cleaning will not remove organic sulfur. For example, 

physical coal cleaning generally removes 40–50 percent of 

the pyritic sulfur in typical Illinois coal. The end result 

is a 20–25 percent reduction in SO2 emissions (Southern 

Illinois University, 2005).

In addition to lowering air emissions, coal washing also 

increases the heating value of the fuel. This lowers the 

transportation cost of the fuel per unit of energy, offseting 

the costs associated with the coal washing. Coal washing 

also reduces the maintenance costs associated with the 

boiler. According to a recent conference paper, unplanned 

outages—resulting from the use of coal with higher ash 

and sulfur content—can cost a modest size coal plant 

millions of dollars in revenue (Cole, 2004).

Boiler Control Technologies

As indicated in Table 7.1, steam boilers are the dominant 

technology used in the electric generating sector and coal 

accounts for the largest segment of the boiler population. 

There are two basic categories of technologies that are 

used to control emissions from EGU boilers: combustion 

controls and post-combustion controls. 

Combustion controls involve modifi cations to the 

combustion process designed to reduce the formation of 

NOx in the boiler. The most common technologies used 

in the EGU sector are LNBs and over fi re air (OFA), either 

alone or in combination. 

Post-combustion controls involve the application of backend control systems to capture or convert pollutants 

before they are released to the air. Control technologies 

are available for all of the major pollutants of concern 

addressed in this report: PM2.5, SO2 and NOx. The most 

common technologies include selective catalytic reduction 

(SCR) for NOx control, fl ue gas desulfurization (FGD) or 

scrubbers for SO2 control, and fabric fi lters (also known 

as baghouses) and electrostatic precipitators (ESPs) for 

PM control. A new generation of multi-pollutant control 

technologies is also under development.

The application of combustion and post-combustion 

controls varies depending on the type of boiler and the type 

of fuel combusted. For example, fabric fi lters are not used 

on oil-fi red boilers because particles from oil combustion 

tend to clog the fi lter (EPA, 1998b). In contrast, fabric 

fi lters are highly effective in controlling PM emissions 

from coal- and wood-fi red boilers. Table 7.5 summarizes 

the applications and commercial availability of the various 

combustion and post-combustion control options for EGU 

Table 7.4

Emissions Benefi ts of Fuel Switching at 

Selkirk Plant

Pollutant Coal-Fired 

(Tons/Year)

Natural GasFired 

(Tons/Year)

Percent 

Reduction

PM 1,440 9 99.4%

SO2 850 3 99.6%

NOx 623 66 89.4%

Source: University of Manitoba, 2005
92 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 7.5

Combustion and Post-Combustion Control Options for EGU Boilers

Control Type Control 

Technology

Description Applications and Commercial Availability

Combustion 

controls (for NOx

control)

Low-NOx burners Burner confi guration that limits 

NOx formation by controlling 

temperature profi le in burner 

zone.

Commercially available for boilers, such as 

tangential and wall-fi red boilers, but not all 

boiler types.

Overfi re air Diverts some combustion air 

and reinjects it above main 

combustion zone.

Commercially available. Applicable to most 

boiler types. Must have suffi cient furnace 

height above burners.

Low-NOx burners 

with overfi re air

Combination of new burner 

design and injection of air 

above main combustion zone.

Available in new boiler designs and can be 

retrofi tted to a variety of boiler types.

Reburn Injection of reburn fuel (natural 

gas, fuel oil or coal) for 

combustion above the main 

combustion zone.

Available but not in wide use. Must have 

suffi cient furnace height above burners.

Post-combustion 

controls

SCR Injection of ammonia (NH3) into 

boiler fl ue gas; fl ue gas then 

passed through a catalyst bed, 

where the NOx and NH3 react 

to form nitrogen and water 

vapor.

Available on new boilers and as retrofi t.

SNCR Injection of NH3 or urea in 

the convective pass for NOx

control.

Available on new boilers and as retrofi t.

Wet scrubber Slurry of lime used to absorb 

SO2.

Commercially available and in wide use.

Spray drying Alternative scrubbing technique 

using calcium hydroxide slurry 

that vaporizes in spray vessel 

for SO2 control.

Commercially available and in wide use. 

Primarily for low to medium sulfur fuels.

Electrostatic 

precipitator

Use of grounded electrodes to 

collect particles.

Commercially available and in wide use.

Fabric fi lter (or 

baghouse)

Filtering elements (bags) used 

to collect particles.

Commercially available and in wide use.
 Chapter 7 - Electric Generating Units 93

boilers.

In general, combustion controls (just for NOx) involve 

a lower capital investment and lower operating costs, 

as compared to post-combustion controls. However, 

combustion controls generally produce more modest 

emissions reductions. LNBs and overfi re air can 

achieve a 40–60 percent reduction in NOx emissions, 

while SCR controls can achieve greater than 90 percent 

control. Post-combustion controls (available for a range 

of pollutants) often require large capital expenditures 

with signifi cant on-going operating and maintenance 

costs. Post-combustion controls can also have signifi cant 

energy requirements, requiring a meaningful portion of a 

facility’s electricity output to operate. Wet scrubber units, 

in particular, require as much as 1–2 percent of a power 

plant’s total energy output. Table 7.6 summarizes the 

control-effectiveness and cost-effectiveness of alternative 

EGU control options.

Renewable Generating Technologies

Renewable forms of energy and nuclear power can also 

reduce PM2.5 and PM2.5-precursor emissions by displacing 

the electricity that would otherwise be produced by a 

fossil fuel-fi red power plant. Currently, renewable sources 

of energy contribute less than 10 percent of the electricity 

supplied by the electric power sector; of that 10 percent, 

hydroelectric power provides 82 percent, biomass provides 

9 percent and wind and geothermal each provide 4 percent 

of renewable energy supply (EIA, 2005c). Nuclear power 

contributes 20 percent of the sector’s electricity output 

(EIA, 2005a).

The extent to which non-emitting forms of generation 

reduce PM2.5, SO2 and NOx emissions will depend on the 

types of generation displaced, which varies by region, time 

of day and time of year. Emissions reductions are greatest 

when renewable energy is used to displace generation at a 

coal-fi red power plant with limited pollution controls.

A number of factors limit the widespread adoption 

of renewable energy, despite the sector’s tremendous 

potential. Compared with new fossil fuel-fi red power 

plants, renewable technologies reduce long-term operating 

(primarily fuel) costs, but have high up-front capital costs. 

(See Table 7.7.) In some cases, the savings in fuel costs 

eventually pay back the higher capital costs, but in most 

cases renewable electricity is simply more expensive than 

fossil fuel-based electricity. (This cost disparity would be 

reduced and possibly even reversed if electric generating 

companies were required to internalize the cost of carbon.) 

Also, renewable energy technologies face technical 

challenges in terms of scale, dispatch and proximity to 

transmission systems and, in some cases, strong public 

opposition. For example, there has been local opposition 

to several proposed wind power projects in recent years.

Integrated Gasifi cation Combined Cycle

The abundant domestic supply of coal and rising natural 

gas prices have fueled growing interest in advanced 

coal-based generating technologies, including integrated 

gasifi cation combined cycle (IGCC) technology. Rather 

than burning coal directly, coal gasifi cation reacts coal with 

steam and carefully controlled amounts of air or oxygen 

under high temperatures and pressures. A synthesis gas 

(“syngas”) is formed, typically comprised of hydrogen 

and carbon monoxide (CO). In the IGCC confi guration, 

which combines modern coal gasifi cation technology 

Table 7.6

Cost-Effectiveness of Combustion and Post-Combustion Control Options for EGU Boilers

Control Type Control Technology Control-Effectivenessa Cost-Effectiveness

Combustion 

controls (for NOx)

Low-NOx burners 30%–50% $200–$1,000 per ton of NOx

Overfi re air 20%–30% $250–$600 per ton of NOx

Reburn 30%–60% $500–$2,000 per ton of NOx

Post-combustion 

controls

SCR 70%–90% $1,000–$2,000 per ton of NOx

SNCR 30%–50% $800–$1,500 per ton of NOx

FGD (wet) >90% $200–$5,000 per ton of SO2

FGD (spray dry) 80-90% $150–$4,000 per ton of SO2

Electrostatic precipitator 80%–95% (PM2.5) $48–$520 per ton of PMb

Fabric fi lter (or baghouse) 99% (PM2.5) $37–$303 per ton of PMb

a. Maximum control-effectiveness may exceed the values presented in some cases.

b. Although control effectiveness estimates were available for PM2.5, cost-effectiveness estimates for PM2.5, specifi cally, were not 

available from the sources referenced.

Source: Midwest RPO, 2005; NESCAUM, 2005; EPA, 2003c; EPA, 2003d
94 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

with both gas turbine and steam turbine power generation, 

the syngas is used to fuel a combustion turbine. The 

combustion turbine drives an electric generator, provides 

air under pressure back to the gasifi er, and produces heat 

to generate steam to drive a steam turbine. This combined 

use of combustion and steam turbines signifi cantly boosts 

the effi ciency of the system. IGCC can be used for new 

power plants or for repowering existing facilities.

IGCC has several advantages relative to a conventional 

coal-based power plant, because gasifi cation facilitates the 

removal of pollutants that would otherwise be released into 

the air. The IGCC plant typically achieves 99 percent SO2

removal and 90 percent NOx removal, as well as reduced 

CO2 emissions (relative to a conventional coal-fi red 

power plant, assuming the same level of output). Table 

7.8 presents the permitted emissions rates for a proposed 

IGCC plant in Wisconsin. Despite the advantages, 

however, companies have been reluctant to embrace the 

technology because of the relatively high cost and risk 

that comes with early adoption of new technology. Two 

full scale commercial IGCC electric generating units are 

in operation in the U.S: Tampa Electric Company’s 262 

MW unit at the Polk plant in Florida and Cinergy’s 192 

MW unit at the Wabash River plant in Indiana. Outside 

of the electric generating sector, chemical manufacturers 

rely on gasifi cation technology for chemical production. 

For example, the Eastman Chemical plant in Kingsport, 

Tennessee has utilized coal gasifi cation to produce 

chemicals for more than 20 years (Ferguson, 2003).

Combustion Turbines and Reciprocating 

Internal Combustion Engines

The electric generating sector uses combustion turbines 

and stationary IC engines for peaking and base load 

power generation, as well as for stand-by or emergency 

power. Oil, and to a lesser extent natural gas, are used to 

fuel stationary IC engines in simple cycle or cogeneration 

(electricity production with heat recovery) mode. 

Combustion turbines are generally fueled with natural gas 

and, in some cases, distillate oil. Combined, combustion 

turbines and IC engines contribute 2 percent of EGU PM2.5

and NOx emissions and less than 1 percent of EGU sector 

SO2 emissions (EPA, 2005f).

Internal Combustion Engines. There are two 

basic types of stationary IC engines: spark ignition and 

compression ignition. Spark ignition engines, used in 

stationary applications, typically use a gaseous fuel such 

as natural gas. Compression ignition engines (or diesel 

engines) typically use a liquid fuel such as diesel fuel, but 

they can also operate on a blend of fuels (e.g., natural gas 

and diesel fuel).

Table 7.8

IGCC Permitted Emissions Rates for the 

Elm Road IGCC Plant

Pollutant IGCC Permit Emissions Rates 

(lb/mmBtu)

NOx 0.07

PM10 0.011

SO2 0.03

Source: Clean Air Task Force, 2004

Table 7.7

Costs of Conventional and Renewable Energy Technologies

Technology Size (MW) Capital ($/kw) Fixed O&M ($/kw/yr) Variable O&M ($/MWh)

Natural gas 

combined cycle

250 503 9.74 1.95

Conventional 

pulverized coal

600 1,074 23.36 2.92

Combustion 

turbine

160 383 9.74 3.90

Wind 50 863–1,396 16.12 0

Solar PV 5 3,587 9.49 0

Geothermal 50 1,887–8,985 68–2,274 0

Landfi ll gas 30 1,369–2,656 93.75 0.0094

O&M = Operation and Maintenance

Note: Region-specifi c interconnection costs are assumed to increase the capital costs of wind plants.

Source: EPA, 2005d
 Chapter 7 - Electric Generating Units 95

Table 7.9

Small Engine PM10, SOx and NOx Emissions Factors

Engine Type PM10a SOx NOx

g/hp-hr lb/MWh g/hp-hr lb/MWh g/hp-hr lb/MWh

Diesel < 600 hp 1.00 2.95 0.16 0.49 14.06 41.47

Diesel > 600 hp 0.32 0.94 0.16 0.49 10.86 32.04

Natural gas 0.15 0.45 0.002 0.006 10.89 32.12

Gasoline 0.33 0.97 0.16 0.49 5.00 14.72

a. Although this is labeled PM10, according to NESCAUM (2003) PM2.5 accounts for most of the overall PM emissions from IC engines.

Source: NESCAUM, 2003

IC engines are used in the electric power sector because 

of their low initial capital cost, ease of installation and 

ability to provide intermittent or variable load service. 

Commercially available stationary engines range from 5 

kilowatts (kW) to 7 MW (HARC, 2003). In the electric 

power sector, several large engines will often be used in 

tandem in order to meet load requirements.

Most small-scale electrical generators are diesel engines 

(HARC, 2003). Many diesel engines in the U.S. are 

used for emergency back-up purposes and operate only a 

limited number of hours per year. In a study focusing on 

the Northeast, the Northeast States for Coordinated Air 

Use Management (NESCAUM) reports that 80 percent 

of these engines are intended for emergency use, 19 

percent are used during periods of peak energy demand 

and 1 percent are used for baseload power generation 

(NESCAUM, 2003). Emergency engines are often 

exempt from emissions standards, with their operation 

usually limited to a small number of hours or to specifi c 

emergency situations.

Compression engines, burning diesel fuel, have relatively 

high rates of PM and NOx emissions. NOx emissions 

from an uncontrolled diesel engine typically range from 

10–14 grams per horsepower hour (g/hp-hr), depending 

on the horsepower rating (HARC, 2003). On a pound per 

megawatt hour (MWh) basis, this rate is more than 200 

times higher than that of a combined cycle natural gas 

turbine with SCR controls (NESCAUM, 2003). Diesel 

exhaust also contains numerous toxic and potentially 

carcinogenic components. As compared to diesel-fueled 

compression engines:

Dual fuel compression engines produce relatively 

low PM emissions.

Natural gas-fi red spark ignition engines also 

have relatively low PM emissions. 

Spark ignition engines can produce relatively 

high NOx emissions (MECA, 1997).

•

•

•

Table 7.9 reports typical emissions rates for IC engines.

Several options other than fuel switching are available for 

controlling PM and NOx emissions from stationary diesel 

engines. The most effective NOx control method is SCR. 

For diesel and dual fuel engines, SCR can reduce NOx

emissions by 90 percent or more (EPA, 2003b). Injection 

timing adjustments and lean NOx catalyst technology can 

provide a more modest 15 to 25 percent NOx reduction 

(NESCAUM, 2003). However, timing adjustment 

modifi cations are reported to increase PM emissions 

substantially, and a diesel particulate fi lter (DPF) is 

recommended in order to address the increase in PM 

emissions associated with this option (HARC, 2003).

DPFs and oxidation catalysts can achieve 80–90 

percent and 20 percent reductions in PM emissions, 

respectively (NESCAUM, 2003). Both technologies 

will also substantially reduce hydrocarbon and CO 

emissions. Further, low-sulfur diesel fuel can enhance the 

performance of some of these control options.

Low emissions combustion involves the combustion of 

a very fuel lean mixture (high oxygen content). A fuel 

lean mixture lowers cylinder temperatures and lowers 

NOx formation. This technology is not effective on diesel 

engines but does work for dual fuel engines with pilot 

liquid fuel reduced to 1 percent or less,3 lean burn engines 

and rich burn to lean burn engine conversions (NJ DEP, 

2003). EPA reports a NOx control-effectiveness of 80 

percent and an average cost-effectiveness for large IC 

engines using low emissions combustion technology of 

$540–$890 per ton of ozone season NOx reductions (EPA, 

2003b).

The cost-effectiveness of controlling IC engines varies 

widely, depending on the utilization of the unit. An 

engine that operates only a limited number of hours will 

3. Dual fuel engines are generally started using liquid fuel. Once stable 

operating conditions are reached, the engine is switched over to natural 

gas fi ring. The “pilot liquid fuel” continues to provide a small percentage of the heat input.
96 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

face a relatively high cost per ton of pollutant reduction. 

Other factors that infl uence the cost-effectiveness of 

control include the size of the unit, load and fuel type. 

NESCAUM reports the cost-effectiveness of various 

control technology combinations applied to stationary IC 

engines (NESCAUM, 2003). The results of the analysis 

are presented in Table 7.10. These cost-effectiveness 

estimates refl ect the combined benefi ts of reducing 

multiple pollutants, as well as different annual hours of 

operation. The California Energy Commission reports 

a cost-effectiveness of $11,000–$38,000 per ton of NOx

reduction for SCR controls on a 1 MW diesel generator 

(CEC, 2001). 

Combustion Turbines. The electric power sector uses 

combustion turbines, fueled by natural gas and oil, for 

peaking and base load power generation; these turbines 

typically range in size from 500 kW to 25 MW, or larger. 

The primary pollutants of concern from a combustion 

turbine are NOx and CO. Modern combustion technology 

and back-end control systems are capable of achieving 

extremely low NOx and CO emissions levels.

Combustion turbines used in the electric power sector are 

based on aircraft jet engine technology. A combustion 

turbine power plant consists of a gas compressor, 

fuel combustors and a gas expansion turbine. Air is 

compressed in the gas compressor and energy is added to 

the compressed air by combusting liquid or gaseous fuel 

in the combustor. The hot compressed air is expanded 

through the gas turbine, which drives both the compressor 

and an electric power generator. Gas turbine power plants 

are available as heavy-duty “frame” machines specifi cally 

designed as stationary engines, or as aeroderivative 

machines—aircraft engines adapted to stationary 

applications. 

Several control options are available for reducing 

combustion turbine NOx emissions. The basic options 

are: (1) water or steam injection into the combustion zone; 

(2) dry low-NOx combustion; (3) catalytic combustion; (4) 

SCR; and (5) other catalyst technologies (e.g., SCONOx). 

In some cases, these control options, some of which are 

back-end and some of which are combustion technologies, 

are used in combination to achieve extremely low NOx

emissions rates. 

Water or steam injection systems are designed to lower 

Table 7.10

Cost-Effectiveness of Various Control Options for IC Engines

Technology Controls Basis for CostEffectiveness 

Calculation

Cost-Effectiveness Estimate (by Hours of Operation)

500 Hours 1,000 Hours 2,000 Hours

Back-up diesel 

generator (2,848 

hp)

Diesel particulate 

fi lter (DPF) with 

ultra-low-sulfur 

diesel fuel

Combined CO, 

HC and PM 

reduction

$19,000 per ton $10,000 per ton $5,000 per ton

Shipyard diesel 

generator (1,030 

hp)

DPF and SCR Combined NOx, 

CO, HC and PM 

reduction

$90,000 per ton $46,000 per ton $23,000 per ton

Emergency 

generator (2,841 

hp)

DPF burning 

regular #2 diesel 

fuel

Combined CO, 

HC and PM 

reduction

$65,000 per ton $32,000 per ton $16,000 per ton

Emergency diesel 

generator (2,220 

hp)

Diesel oxidation 

catalyst burning 

#1 and #2 diesel 

fuel

Combined NOx, 

CO, HC and PM 

reduction

$2,000 per ton $1,000 per ton $1,000 per ton

Back-up diesel 

generator (2,220 

hp) 

DPF burning #2 

diesel fuel

Combined CO, 

HC and PM 

reduction

$17,000 per ton $9,000 per ton $4,000 per ton

Back-up diesel 

generator for 

brewery operation 

(1,109 hp)

DPF burning #2 

diesel fuel

Combined CO, 

HC and PM 

reduction

$5,000 per ton $3,000 per ton $2,000 per ton

HC = hydrocarbons, CO = carbon monoxide

Source: NESCAUM, 2003
 Chapter 7 - Electric Generating Units 97

the combustion zone temperature, which will reduce NOx

emissions. As the combustion zone temperature decreases, 

NOx production decreases exponentially. There is a tradeoff, however, between the effi ciency of the unit and the 

amount of water injected. Turbine manufacturers have 

been increasing the fi ring temperatures of gas turbines in 

order to improve their thermodynamic effi ciency. Water 

injection reduces the overall thermal effi ciency of the unit 

and tends to increase CO emissions. Water injection can 

generally achieve an emissions rate of 25 parts per million 

(ppm) with units fi ring natural gas and 42 ppm with units 

fi ring oil (Schorr, 1999).

Like the systems used for boilers and IC engines, SCR 

controls for gas turbines involve the injection of a 

reagent—ammonia—into the exhaust gas stream. The 

reagent and NOx react in the presence of a catalyst to form 

molecular nitrogen and water.

New gas combustion systems are capable of achieving 

extremely low levels of NOx emissions without add-on 

controls. For example, GE frame turbines are capable of 

achieving emissions levels of 9 ppm NOx with dry lowNOx combustion (Schorr, 1999). The technology uses 

staged combustion and lean premixed fuel-air mixtures to 

reduce NOx emissions.

SCONOx is a catalytic technology that removes both 

NOx and CO without the use of supplementary chemical 

reagents (e.g., ammonia). The system is currently installed 

only on a 32 MW cogeneration unit in California and a 5 

MW unit in Massachusetts (Czarnecki, 2005).

XONON is a catalytic combustion technology, developed 

by Catalytica and Kawasaki, which operates at much lower 

gas temperatures, vastly reducing the amount of thermal 

NOx generated in the combustion process. The California 

Air Resources Board (CARB) certifi ed XONON in June 

2002 at 2.5 ppm (dry volume basis) NOx and 6.0 ppm (dry 

volume basis) CO. The system is currently installed at a 

1.5 MW unit in California.

EPA reports a cost of $3,000–$6,000 per ton of NOx

removed with SCR controls on a large (greater than 75 

MW) gas turbine and a cost of $2,000–$10,000 per ton of 

NOx removed for a small (5 MW) turbine (EPA, 2003a). 

GE reports the annual cost of reducing NOx using SCR 

from 9 ppm to 3.5 ppm for a specifi ed 170 MW gas turbine 

operating 8,000 hours per year at $8,000–$12,000 per ton 

of NOx removed (Schorr, 1999).

Regulatory Authority

EGU emissions contribute signifi cantly to local, regional 

and national air pollution problems, including PM2.5

pollution. Numerous state and federal programs stemming 

from Titles I and IV of the Clean Air Act regulate these 

emissions. The mix of regulatory programs results in a 

range of EGU emissions limits and performance standards, 

imposed by permits and state and federal regulatory 

programs, including emissions trading programs such as 

the Clean Air Interstate Rule (CAIR) and the Acid Rain 

SO2 Program. 

As we have indicated in other chapters, the states and the 

federal government share responsibility for regulating 

criteria pollutants (e.g., PM, SO2, NOx) from stationary 

sources like EGUs. The federal government has more of 

the burden of regulating toxic air pollutants, but—for both 

criteria pollutants and air toxics—states and local areas are 

free under federal law to adopt more stringent standards 

than the Clean Air Act requires. 

This section describes federal standards that apply under 

the Clean Air Act to pollutant emissions from EGUs. 

Reasonably Available Control Technology

State Implementation Plans (SIPs) for areas that are in 

nonattainment of federal ambient air quality standards 

must include Reasonably Available Control Technology 

(RACT) requirements for new and existing sources. 

RACT standards are non-binding federal guidelines; 

for volatile organic compounds (VOCs), the guidelines 

are known as Control Technique Guidelines (CTGs). 

Guidelines known as Alternative Control Techniques 

(ACTs) outline the control technologies that are available 

to address NOx emissions from specifi c source sectors, but 

do not specify actual RACT limits. There are no sectorspecifi c ACTs or CTGs for SO2, PM10 or PM2.5.

There are ACTs applicable to NOx emissions from 

stationary gas turbines and utility boilers, which can be 

found at EPA’s website (www.epa.gov/ttn/catc/products.

html#aptecrpts). SIP writers should bear in mind that 

although the ACTs may provide a starting point, they 

are unlikely to represent the actual RACT limits that 

states will choose to adopt. That is the case because 

RACT standards are intended to refl ect advancements in 

technology, and most of the ACTs are outdated—some, 

seriously so. Additionally, the ACTs are guidelines only, 

not actual federal limits. Even if they were federal limits, 

many states would have the leeway to enact more stringent 

standards. And since the ACTs do not set limits, even 

state prohibitions against enacting standards that are more 

stringent than federal requirements may be inapplicable.

New Source Performance Standards

New Source Performance Standards (NSPS) typically 

apply to major stationary sources (for EGUs, greater 

than 250 MMBtu per hour heat input) in specifi c source 

categories, in both attainment and nonattainment areas, 

when they are fi rst constructed, reconstructed or modifi ed.
98 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

There are two sets of NSPS requirements, the applicability 

of which depends on the date that plant construction, 

reconstruction or modifi cation commenced. Plants that 

commenced construction after August 17, 1971 have one 

set of NSPS limits (40 CFR §§60.40, et seq. (subpart D)); 

and plants that commenced construction after September 

18, 1978, a different set (40 CFR §§60.40a, et seq. (subpart 

Da)). Thus, plants built or under construction prior to 

August 17, 1971 are not subject to NSPS limits without a 

major modifi cation after the NSPS rules took effect. 

The NSPS are not dependent on the type of boiler 

technology, but they do vary according to the type of fossil 

fuel consumed (although this is not the case for the new 

NSPS discussed immediately below). Table 7.11 shows the 

current NSPS limits.

In February 2005, EPA proposed changes to the NSPS 

limits at 40 CFR §§60.40a, et seq. (subpart Da). The 

current standards were originally promulgated on June 11, 

1979. The fi nal rule was released on February 9, 2006 and 

amends the emissions limits for PM, SO2 and NOx from 

EGU steam generating units. Only those units that begin 

construction, reconstruction or modifi cation after February 

28, 2005 will be affected by the proposed amendments. 

The fuel-neutral limits for these new units are summarized 

in Table 7.12, as are the limits advocated by STAPPA and 

ALAPCO in response to EPA’s proposal.

EPA promulgated the current standards for stationary 

combustion turbines, shown in Table 7.13, in 1979. They 

are available at 40 CFR §§60.330, et seq. (subpart GG). In 

February 2005, EPA also proposed changes to the NSPS 

for NOx and SO2 emissions from stationary combustion 

Table 7.11

NSPS for Fossil Fuel-Fired Steam Generators Greater than 250 MMBtu per hour (40 CFR 

§§60.40, et seq. (subpart D), 40 CFR §§60.40a, et seq. (subpart Da))

Fuel Type Applicable 

Datesa

PM Limit Opacity 

Limit b

SO2 Limitc NOx Limitc

Gases 

(natural 

gas)

After August 17, 

1971

0.1 lb/MMBtu 20% NA 0.2 lb/MMBtu

After September 

18, 1978

0.03 lb/MMBtu 20% 0.8 lb/MMBtu and 90% reduction, 

or 0% reduction when emissions 

are less than 0.2 lb/MMBtu

0.2 lb/MMBtud

Liquids (oil) After August 17, 

1971

0.1 lb/MMBtu 20% 0.8 lb/MMBtu 0.3 lb/MMBtu

After September 

18, 1978

0.03 lb/MMBtu 

(70% reduction from 

potential combustion 

concentration)e

20% 0.8 lb/MMBtu and 90% reduction, 

or 0% reduction when emissions 

are less than 0.2 lb/MMBtu

0.3 lb/MMBtuf

Solids 

(coal)

After August 17, 

1971

0.1 lb/MMBtu 20% 1.2 lb/MMBtu 0.7 lb/MMBtug

After September 

18, 1978

0.03 lb/MMBtu 

(99% reduction from 

potential combustion 

concentration)

20% 1.2 lb/MMBtu and 90% reduction, 

or 70% reduction when 

emissions are less than 0.60 

lb/MMBtuh

0.6 lb/MMBtui

a. The dates after which units commenced construction, reconstruction or modifi cation.

b. In all cases, except for one six-minute period per hour of not more than 27% opacity.

c. Subpart D contains an equation for facilities that burn multiple fuels and have an applicable date of August 17, 1971. Subpart Da 

contains an equation for facilities that burn multiple fuels and have an applicable date of September 18, 1978. 

d. Coal-derived gaseous fuels are subject to a NOx limit of 0.5 lb/MMBtu.

e. “Potential combustion concentration” means the theoretical emissions (lb/MMBtu heat input) that would result from combustion of a 

fuel in an uncleaned state without emissions control systems), and is further defi ned at 40 CFR § 60.41a.

f. Coal-derived liquid fuels and shale oil are subject to a NOx limit of 0.5 lb/MMBtu.

g. Except for lignite used in units commencing construction after December 22, 1976 and mined in North Dakota, South Dakota or 

Montana and burned in a cyclone-fi red unit (NOx limit of 0.8 lb/MMBtu), and other lignite (NOx limit of 0.6 lb/MMBtu).

h. SO2 emissions are limited to 1.2 lb/MMBtu for any affected facility that combusts 100% anthracite; and 1.2 lb/MMBtu and 85% 

reduction for any affected facility that combusts solid solvent refi ned coal.

i. Except subbituminous and coal-derived fuels (NOx limit of 0.5 lb/MMBtu) and any fuel containing more than 25% lignite by weight (NOx

limit of 0.8 lb/MMBtu).
 Chapter 7 - Electric Generating Units 99

turbines, and these, too, were released on February 9, 

2006. The new NSPS apply to new stationary combustion 

turbines that commence construction, reconstruction or 

modifi cation after February 18, 2005 (EPA, 2006a). (We 

have not included a table showing the new NSPS for new 

stationary combustion turbines because of the complexity 

of the new standards, which vary based on the fuel input 

of the unit at peak load, fuel, application, and location of 

the turbine.)

There are no existing NSPS for IC engines. However, 

on July 11, 2005, EPA proposed a rule that would reduce 

emissions of air pollutants from stationary compression 

ignition IC engines. The proposed NSPS would limit 

emissions of PM, SO2 and NOx from stationary diesel 

IC engines to the same levels required by EPA’s nonroad 

diesel engine regulations (see Chapter 14, Nonroad 

Equipment). New, modifi ed and reconstructed stationary 

diesel engines would have to comply with the proposed 

rule. A new stationary diesel engine is one that is 

ordered after July 11, 2005 and manufactured after April 

2006. Stationary diesel engines that start modifi cation or 

reconstruction after July 11, 2005 also are subject to the 

rule. The proposed rule also contains fuel requirements 

that limit the amount of sulfur in the diesel fuel used to 

run these engines (EPA, 2005g).

Regional Haze/Best Available Retrofi t 

Technology

Under the regional haze program, Best Available Retrofi t 

Technology (BART) requirements apply to PM2.5 and 

PM2.5-precursor emissions from large sources that fall 

into 26 identifi ed source categories and that began 

Table 7.12

Fuel-Neutral NSPS for EGU Boilers Constructed, Reconstructed or Modifi ed after

February 28, 2005

Pollutant Facility Type

Limits Promulgated by EPA

Limits Suggested by

STAPPA and ALAPCO

lb/MWh lb/MMBtu lb/MMBtu

PMa New or 

reconstructed

- 0.015 or 99.9% reduction -

Modifi ed - 0.015 or 99.8% reduction

SO2 New 1.4 or 95% reductionb - 0.10

Reconstructed - 0.15 or 95% reduction

Modifi ed - 0.15 or 90% reduction

NOx New 1.0 - 0.07–0.08

Reconstructed - 0.11

Modifi ed - 0.15

a. NSPS limit does not include condensable PM. STAPPA and ALAPCO have recommended that EPA adopt a PM NSPS that includes 

both fi lterable and condensable PM.

b. The SO2 limit for new EGUs that burn over 75% coal refuse (by heat input) is 1.4 lb/MWh or 94% reduction.

Source: EPA, 2006; STAPPA and ALAPCO, 2005

Table 7.13

NSPS for Stationary Gas Turbines (40 CFR §§60.330, et seq. (subpart GG))

Fuel Type Applicable Dates Turbine Size NOx Limit SO2 Limit

Natural gas October 3, 1977 >100 mmBtu/hour 75 ppmb 150 ppm at 15% 

on a dry basisa

October 3, 1977 10–100 mmBtu/hour 150 ppmb

a. Fuel must have a sulfur content less than or equal to 0.8% by weight (8000 ppm).

b. May be slightly higher or lower based on site-specifi c calculations.
100 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

operation between 1962 and 1997, in both attainment 

and nonattainment areas. The source categories include 

fossil fuel-fi red steam electric plants of more than 250 

MMBtu per hour heat input. However, states have not yet 

developed their BART rules.

New Source Review/Prevention of Signifi cant 

Deterioration

New Source Review (NSR) and Prevention of Signifi cant 

Deterioration (PSD) requirements apply to new and 

modifi ed large stationary sources in nonattainment and 

attainment areas, respectively. The programs subject 

plants in nonattainment areas to Lowest Achievable 

Emission Rate (LAER) standards and in attainment areas 

to Best Available Control Technology (BACT). Neither 

BACT nor LAER standards are codifi ed because they are 

intended to refl ect technology advancements as they occur.

STAPPA and ALAPCO completed a review of SO2 and 

NOx BACT determinations for coal-fi red EGU boilers 

in March 2004 (STAPPA and ALAPCO, 2004). As part 

of their review, STAPPA and ALAPCO identifi ed BACT 

levels for new and existing coal-fi red EGU boilers. They 

compiled the new boiler BACT levels based on data 

in EPA’s RACT/BACT/LAER Clearinghouse, and the 

existing boiler BACT levels from recent EPA consent 

decrees in PSD cases. 

For SO2, STAPPA and ALAPCO reported a BACT level of 

0.10 lb/MMBtu for new coal-fi red EGUs and a BACT level 

of 0.15 lb/MMBtu for existing coal-fi red EGUs. For NOx, 

they reported a BACT level of 0.07 lb/MMBtu for new 

EGUs and a BACT level of 0.10 lb/MMBtu for existing 

EGUs.

STAPPA and ALAPCO did not review BACT 

determinations for natural gas- or residual oil-fi red EGU 

boilers, but simply notes that BACT levels more stringent 

than those for coal-fi red boilers are feasible for gas- and 

residual oil-fi red EGU boilers (STAPPA and ALAPCO, 

2004).

CARB made BACT determinations for PM, SOx and NOx

emissions from a modifi ed natural gas-fi red EGU boiler 

in 2002. The limits were 0.01 grains per dry standard 

cubic foot for PM; 0.2 lb/MMBtu for SOx; and 5 ppm (at 3 

percent oxygen, approximately 0.005 lb/MMBtu) for NOx. 

CARB based the PM and SOx determinations on good 

combustion practices and the low sulfur content of natural 

gas. It based the NOx determination on the combined use 

of LNBs, FGR and SCR (CARB, 2005).

Offi cials at CARB have indicated in discussions that new 

natural gas-fi red combined cycle turbines and cogeneration 

facilities are generally permitted at a NOx limit of 2.0 ppm 

over a one hour average, and simple cycle turbines are 

permitted at a limit of 2.5 ppm over a one hour average 

(Kato, 2005). Also, different limits sometimes allow 

higher emissions levels during certain periods, for example 

when a unit is ramping up or down.

The Minnesota Pollution Control Agency (MPCA) recently 

issued BACT determinations for two wood-fi red utility 

boilers. The boilers are both new processes at existing 

facilities. The BACT determinations set limits for PM10

and NOx. The MPCA based the PM10 BACT limit on use 

of an ESP and set the limit at 0.025 lb/MMBtu. It set the 

NOx limit at 0.15 lb/MMBtu based on use of selective noncatalytic reduction (SNCR) controls (EPA, 2005e).

Maximum Achievable Control Technology

Maximum Achievable Control Technology (MACT) 

standards address emissions of hazardous air pollutants 

(HAPs) from new and existing sources in identifi ed 

industry categories. They apply in both attainment and 

nonattainment areas to sources with potential emissions of 

10 tons per year of a single HAP or 25 tons per year of 

combined HAPs.

We have discussed MACT standards for certain other 

source categories, where EPA has regulated PM as a 

surrogate for HAPs—which it does not do for EGU boilers, 

IC engines or combustion turbines. For that reason, we 

have not included a discussion of MACT standards in this 

chapter.

The Acid Rain Program

The 1990 Amendments to the Clean Air Act established 

the Title IV Acid Rain Program to reduce EGU SO2 and 

NOx emissions. The Title IV SO2 reduction program uses 

a cap-and-trade approach: power plants are not subject 

to specifi c emissions rate limits but, instead, total SO2

emissions from affected sources are capped at a specifi c 

tonnage. Affected facilities under the program comply 

by obtaining emissions allowances in an amount equal 

to their annual emissions. EPA has allocated sources 

a calculated number of allowances, and sources must 

purchase allowances in the market or from EPA to meet 

any shortfall. Sources that install pollution controls 

may have an excess of allowances, enabling them to sell 

allowances.

The Acid Rain SO2 Program has two phases. Phase I 

began in 1995 and affected 263 EGUs at 110 mostly coalfi red power plants located in 21 eastern and midwestern 

states. Phase II, which began in 2000, established an 

annual tonnage cap of 8.95 million tons and brought 

smaller coal-fi red EGUs and oil and natural gas generators 

into the program. Currently, the SO2 program covers 

virtually all EGUs burning coal, oil and natural gas, with 

an output capacity greater than 25 MW.
 Chapter 7 - Electric Generating Units 101

The Acid Rain Program also reduces NOx emissions in 

two phases, with boiler design-specifi c emissions limits 

(not with a cap-and-trade approach). In general, power 

plants affected by the NOx limits must install some type 

of NOx pollution control device, such as LNB technology. 

The NOx requirements apply nationally to existing EGUs 

and to new power plants beginning operation after the 

start of the program.

Clean Air Interstate Rule

In 1998, EPA promulgated the NOx SIP Call, requiring 

NOx emissions reductions in 22 states in the eastern U.S. 

The rule required affected states to amend their SIPs and 

limit NOx emissions to meet EPA-specifi ed ozone season 

NOx emissions budgets. Although the NOx SIP Call 

did not mandate the specifi c sources that were required 

to reduce emissions, EGU emissions reductions were 

generally the most cost-effective option and were at the 

core of each affected state’s strategy to meet its assigned 

NOx budget. 

EPA followed the NOx SIP Call in March 2005 with CAIR, 

aimed at addressing pollution transport that contributes 

to eight-hour ozone and PM2.5 nonattainment in the 

eastern U.S. CAIR identifi es 28 states and the District 

of Columbia (Figure 4.1 in Chapter 4, The Clean Air Act, 

shows the affected area) as contributing to unhealthy levels 

of ozone and/or PM2.5 in downwind nonattainment areas, 

and subjects them to additional NOx and SO2 emissions 

reductions. CAIR requires states contributing to PM2.5

nonattainment to achieve annual NOx and SO2 emissions 

reductions and states contributing to ozone nonattainment 

to achieve further seasonal NOx emissions reductions. 

States may choose the way in which they achieve these 

reductions, but it is expected that most, if not all states, will 

opt (at a minimum) to cap emissions of EGUs according 

to the budgets established by EPA and to participate in 

the EPA administered emissions trading programs (EPA, 

2005c).

Assuming that all of the affected states opt to participate 

in the EPA administered trading program, EGU sources 

in the CAIR states will have to retire two SO2 allowances 

for every one ton of emissions beginning in 2010. This 

effectively requires a 50 percent reduction in allowable 

emissions. Banked allowances, issued for years prior to 

2010, can be used on a one-for-one basis. In the second 

phase of the program, beginning in 2015, SO2 allowances 

(vintage 2015 and beyond) must be retired at a ratio of 

2.86 allowances for every one ton of emissions. In terms 

of NOx, reductions, the CAIR program establishes two 

separate NOx trading programs, an annual NOx trading 

program and an ozone season NOx trading program. The 

fi rst phase of NOx reductions will be implemented in 2009, 

and the second phase in 2015.

Table 7.14

State Programs to Reduce EGU NOx and SO2 Emissions beyond Federal Requirements

State Affected 

Sources

Pollutant Reduction 

Requrement

Effective Date Comments

MA Six oldest 

power 

plants in 

state

NOx Annual NOx

rate of 1.5 lb/MWh

Oct. 2004 Implemented through 

regulations. PM2.5 and 

CO set aside for future 

consideration. CO2 cap 

proposed in Dec. 2005.

SO2 Phase 1: 6.0 lb/MWh

Phase 2: 3.0 lb/MWh

Phase 1: Oct. 2004

Phase 2: Oct. 2006

NC 14 power 

plants in 

state

NOx 77% reduction 

(annual NOx)

2009 Enacted through legislation in 

2002. Future consideration 

to be given to mercury and 

CO2. SO2 73% reduction 2013

NH Six units 

at three 

plants

NOx 70% reduction based on 

1.5 lb/MWh rate

Dec. 2006 Enacted through legislation 

in 2002. Also includes a CO2

cap at 1990 levels.

SO2 75% reduction based on 

3.0 lb/MWh rate

Dec. 2006

NY All units 

25 MW or 

greater

NOx Annual NOx cap-and-trade 

budget based on at 0.15 

lb/mmBtu

2004 Implemented through 

regulations.

SO2 50% reduction below 

Phase 2 Acid Rain levels

2005-2008 phase in
102 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

State and Local Policy Measures

As we have discussed in the Introduction to this report, the 

Clean Air Act allows state and local agencies to adopt more 

stringent standards than the Act itself requires, although in 

some instances state law limits this authority. We assume 

that SIP writers are familiar with applicable local laws and 

regulations that address this issue. In the Introduction, we 

have also outlined possible approaches to the imposition of 

more stringent state and local standards, such as requiring 

sources that have not yet been required to meet BACT/

LAER standards to achieve those limits.

State and local authority to tighten Clean Air Act 

requirements on new and existing sources and to impose 

air pollution limits on sources that have heretofore been 

unregulated applies to the EGU sector as well as other 

industry sectors. However, a number of additional 

opportunities to reduce emissions from EGUs are worthy 

of consideration. Depending on the scope of state 

environmental law, some of the measures discussed below 

will fall within the purview of environmental regulators; 

others may require additional legislative authority.

Note that we discuss the opportunities for emissions 

reductions through the promotion of energy-effi ciency 

programs mainly in Chapter 18, Residential Fuel 

Combustion and Electricity Use, rather than in this chapter. 

Nonetheless, the demand side management opportunities 

for EGUs are substantial.

State Laws and Regulations Limiting 

Emissions from New and Existing EGUs

As described above, a number of federal programs limit 

emissions from EGUs. However, as a matter of federal 

law, existence of these programs does not preclude states 

from passing their own laws or regulations to achieve 

further reductions. Several states have passed laws (New 

Hampshire, North Carolina) or regulations (Massachusetts, 

New York) aimed at reducing EGU emissions beyond 

federal requirements. Table 7.14 provides a brief overview 

of these programs.

State programs can be patterned on existing emissions 

trading programs, which establish an emissions budget and 

allow for emissions trading fl exibility (e.g., the New York 

program), or they can impose an emissions performance 

requirement on EGUs, with limited or no fl exibility for 

emissions averaging or trading. (The Massachusetts, New 

Hampshire and North Carolina programs limit emissions 

and constrain compliance fl exibility.) Either approach can 

achieve emissions reductions beyond those mandated by 

federal laws, although trading programs generally reduce 

the costs of compliance.

Additionally, some smaller EGUs fall below federal 

regulatory size thresholds, leaving them exempt from 

federal air pollution control limits. In some cases, state 

and local regulators have imposed emissions standards on 

these sources. For example, California (in particular, the 

San Joaquin Valley Unifi ed Air Pollution Control District), 

New Jersey and Washington have all regulated units much 

smaller than the federal standards address. The Ozone 

Transport Commission (OTC) has also developed a model 

rule with fuel-specifi c emissions standards for NOx for both 

new and existing non-emergency natural gas and diesel 

engines. In addition, the Regulatory Assistance Project 

has developed a model rule for controlling emissions 

from distributed generation units. The rule—which 

deals with PM10, not PM2.5—has been or is soon expected 

to be adopted either partially or entirely by Connecticut, 

Delaware, Maine, Maryland, Massachusetts and Rhode 

Island (Regulatory Assistance Project, 2006).

Fuel Sulfur Limits

In addition to the stack emissions limits described above, 

state and local agencies have opted in some cases to 

regulate the concentrations of sulfur in fuel, for example, 

by regulating the sulfur content of fuel oil.

In 2000, the Connecticut Department of Environmental 

Protection (DEP) adopted regulations limiting the sulfur 

content of fuel oil used by power plants (RCSA §22a174-19a). Effective January 1, 2002, affected units that 

combust liquid or gaseous fuels are subject to a fuel sulfur 

limit of 0.5 percent by weight. Effective January 1, 2003, 

the fuel sulfur limit is reduced to 0.3 percent by weight. 

Alternatively, an affected source can meet an average SO2

emissions rate of 0.33 lb/MMBtu. The DEP Commissioner 

can suspend the fuel sulfur limits in the event of a fuel 

supply emergency, in which case the Commissioner can 

require affected sources to offset excess emissions with 

SO2 allowances.

The New York State Department of Environmental 

Conservation regulates the sulfur content of oil and coal 

used by stationary combustion sources (6 NYCRR §225). 

The sulfur limits vary by area within the state. The lowest 

limits apply in New York City: (1) 0.30 percent sulfur by 

weight for residual oil, (2) 0.20 percent sulfur by weight 

for distillate oil and (3) 0.2 lb of sulfur per MMBtu 

gross heat content for solid fuels. As in Connecticut, the 

Commissioner has the authority to suspend the standards 

in the event of a supply shortage.

State Utility Regulatory Programs

An alternative approach for states to consider is to provide 

EGU owners incentives to install pollution controls by 

enabling the installation costs to be recovered through 

utility rates for a limited time only. Rate recovery for 

pollution control investments exists in states that have 

not deregulated (or “restructured”) their electric industry. 

However, some states that still regulate retail electricity 
 Chapter 7 - Electric Generating Units 103

supply have enacted measures that go even a step further to 

facilitate the recovery of pollution control costs, e.g., preapproval statutes and a variety of tax measures (NARUC, 

2004). Indiana, Arkansas, Kentucky and Wisconsin are 

among the states that facilitate recovery of control costs. 

Implementation of this type of utility rate program would 

be more diffi cult in states with deregulated electricity 

markets, although even in these states it would be possible, 

using a wires or system benefi ts charge as the mechanism 

for recovering the control costs. This type of mechanism 

would enable unregulated power producers to receive 

compensation for installing controls on power that they 

sold to regulated retail electricity providers (i.e., the 

providers of transmission and distribution services) in the 

state. 

Regional CAIR “Plus” Approaches

Another alternative for states to consider is supporting a 

regional approach for pursuing deeper or quicker reductions 

in SO2 and NOx emissions from EGUs than those provided 

for in CAIR. STAPPA and ALAPCO published a strategy 

that calls for a national SO2 cap of 1.26-1.89 million tons 

per year (as compared to a baseline of 10.6 million tons 

in 2001) by 2013, and a NOx cap of 0.88-1.26 million tons 

per year by the same date (as compared to a baseline of 4.7 

million tons in 2001) (STAPPA and ALAPCO, 2004).

The OTC plans to use a regional partnership and a model 

rule to implement a program that goes beyond CAIR for 

EGUs and large industrial boilers. The OTC would use 

the basic structure of CAIR to implement tighter emissions 

caps. The OTC aims to develop regional partnerships and 

a model rule in 2006, followed by a fi rst phase of controls 

in 2009 and a second phase in 2012 (InsideEPA, 2006). In 

Phase 1, the program would be based on an SO2 emissions 

rate of 0.24 lb/MMBtu and a NOx emissions rate of 0.12 

lb/MMBtu. In Phase 2, the caps would be ratcheted down 

based on an SO2 emissions rate of 0.14 lb/MMBtu and a 

NOx emissions rate of 0.08 lb/MMBtu (OTC, 2005). State 

support for such efforts could increase the likelihood of 

other regional programs.

States should also consider national and regional 

approaches to achieving more stringent and expeditious 

reductions than CAIR.

CAIR NOx Allowance Allocations

Another option is to pursue an allocation of CAIR 

NOx emissions allowances that provides incentives 

for renewable energy and energy-effi cient electricity 

generation. Under the CAIR program, states are assigned 

NOx budgets by EPA, but are given fl exibility in allocating 

the allowances to their sources. (The same fl exibility is not 

available for SO2 allowance allocations, which are based on 

the historic permanent allocation methodology embodied 

in the Acid Rain SO2 Program.) For NOx allocations, 

however, states can choose their allocation methodology, 

including a distribution that allocates allowances directly 

to or to a set-aside for non-emitting sources, energyeffi ciency projects or other recipients. States are also 

free to choose an output-based allocation scheme, which 

favors more effi cient (and thus less polluting) generation. 

State allocations to renewable energy, energy-effi ciency 

or system benefi ts programs can serve two purposes: (1) 

tightening the cap on affected sources—which will have 

fewer allowances allocated to them and, therefore, more of 

an incentive to install pollution controls; and (2) providing 

a source of revenue for funding projects or programs 

that help to reduce emissions. STAPPA and ALAPCO 

have prepared the document Alternative NOx Allowance 

Allocation Language for the Clean Air Interstate Rule,

which contains alternative regulatory language for NOx

allocation that can provide opportunities to promote clean 

technologies.

Renewable Energy Programs

Apart from allocation schemes for CAIR NOx allowances 

that encourage the development of renewables, most states 

have programs in place to support renewable energy. To 

the extent non-emitting renewable energy resources 

(such as wind and solar) replace new or existing fossil 

generation, emissions from EGUs are reduced. Of course, 

not all renewables used to generate electricity will result 

in zero emissions. For example, combustion of renewable 

biomass resources will not necessarily be benefi cial in 

addressing PM2.5 air quality concerns. 

A Renewable Portfolio Standard (RPS) requires that a 

minimum amount of renewable energy be included in 

the portfolio of electricity resources of retail electricity 

providers serving a state. RPS programs already 

have been adopted by the District of Columbia and 21 

states—Arizona, California, Colorado, Connecticut, 

Hawaii, Illinois, Iowa, Maine, Maryland, Massachusetts, 

Minnesota, Montana, Nevada, New Jersey, New Mexico, 

New York, Pennsylvania, Rhode Island, Texas, Vermont 

and Wisconsin (Pew Center on Global Climate Change, 

2006). These programs aim to increase the amount of 

electricity produced from renewable energy resources 

by expanding the markets for this product. For example, 

California requires 20 percent renewable generation 

by 2017, New York requires 25 percent by 2013 and 

Pennsylvania requires 18 percent by 2020 (Pew Center 

on Global Climate Change, 2005). (These percentages 

are not exactly comparable, because the states vary in the 

resources they defi ne as renewable.) RPS programs have 

the disadvantage that they do not specify where renewable 

energy resources must be developed, so that a state’s RPS 

may stimulate development of renewables elsewhere, 

limiting the program’s impact on local air quality.

Another means of supporting renewables is through public 
104 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

benefi ts funding. The funding pool can be created through 

fees placed on electricity companies or customers. Such 

fees are sometimes referred to as system benefi t charges. 

A number of states adopted system benefi ts charges 

as part of electricity restructuring initiatives. A state 

seeking to improve EGU emissions performance should 

consider enacting or expanding renewable energy funding 

initiatives to improve the overall emissions profi le of the 

its EGU fl eet.

Limits on Back-Up Fuels

In the face of rising fuel prices, state and local agencies 

should evaluate whether increases in the use of backup fuels are increasing emissions signifi cantly. In some 

cases, the emissions limits that apply to back-up fuels are 

less stringent than those applicable to a facility’s primary 

fuel. For example, a natural gas-fi red boiler with oil backup will generally be subject to a more restrictive standard 

when burning natural gas. One way for operating permits 

to address this issue is to restrict the operating hours of 

the unit on the back-up fuel. Cap-and-trade programs 

that restrict emissions-sector wide can also address this 

concern.

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adopted by OTC Member States, June 8, 2005.

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108 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

The pulp and paper industry converts harvested wood and 

recycled fi bers (e.g., rags or wastepaper) into commodity 

grades of wood pulp, primary paper products and paper 

board products. The U.S. is the world leader in the pulp 

and paper business, producing about 28 percent of the 

world’s pulp and 25 percent of total world output of 

paper and paperboard. Fueling this large manufacturing 

sector is the nation’s demand for paper products. The 

U.S. consumed close to 96 million tons of paper products 

in 2001, about 691 pounds per capita (DOE, 2005). The 

industry is especially important in many rural economies, 

where the local paper or lumber mill is often the area’s 

largest employer.

The pulp and paper sector is divided into three distinct 

segments. Pulp making turns raw wood fi ber or recycled 

fi ber into a pulp and bleaches the pulp to varying degrees of 

brightness as required by the fi nal product. Paper making 

takes the bleached or unbleached pulp and processes it into 

sheets of paperboard or paper. Converting operations use 

these primary materials to manufacture more specialized 

products, such as paperboard boxes, writing paper and 

tissue paper (Davis, 2000; EPA, 2002).

Among the various processes involved in the production 

of paper, the pulping process—which produces particulate 

matter (PM), sulfur dioxide (SO2), nitrogen oxides 

(NOx) and other air pollutants—is the largest source of 

emissions. Paper mills and converting facilities have far 

lower emissions and are discussed only briefl y in this 

chapter. The vast majority of pulp mills (over 80 percent) 

use the kraft pulping process. 

There are four primary sources of emissions in the kraft 

pulping process: (1) recovery furnaces (or recovery 

boilers); (2) smelt dissolving tanks (SDTs); (3) lime kilns; 

and (4) power boilers.1

 The last of these sources, power 

boilers, are discussed primarily in Chapter 5, Boiler 

Technologies, is Chapter 6, Industrial and Commercial 

Boilers. This chapter focuses on emissions, emissions 

limits and control technologies for recovery furnaces, 

SDTs and lime kilns.

1. Recovery boilers are used to recycle chemicals used in the pulping 

process. Power boilers are used to generate energy for the pulping 

process and steam for paper making dryers.

Chapter 8

Pulp and Paper
 Chapter 8 - Pulp and Paper Industry 109

Sector Profi le

As noted in the Introduction, the U.S. produces about 

25 percent of the world’s paper and paperboard (DOE, 

2005). More than 50 percent of the wood cut in the U.S. 

is eventually used for paper and paperboard (STAPPA 

and ALAPCO, 1999). In 1998, the U.S. Census Bureau 

reported 514 pulp and paper mills and over 6,000 

converting facilities in the U.S. The majority of converting 

facilities are small, with approximately 75 percent having 

fewer than 100 employees. By contrast, two-thirds of 

pulp and paper mills have more than 100 employees (EPA, 

2002).

There are three general types of pulp and paper facilities: 

pulp mills, paper and paperboard mills, and converting 

facilities. Pulp mills separate the fi bers of wood or other 

recycled materials to create pulp. In the pulping process, 

mills may use chemical, semichemical, or mechanical 

processes. Paper and paperboard mills are primarily 

engaged in manufacturing paper and paperboard from 

wood pulp and other fi ber pulp. Converting facilities turn 

paper and paperboard into a variety of products, including 

paper bags, boxes, envelopes and stationary products. The 

paper mill sector includes integrated mills, where pulping 

and paper making occur on-site. As a result, regulations 

covering emissions from the pulping process refer to the 

regulated facilities as “pulp and paper mills” (EPA, 2002).

The geographic distribution of pulp and paper mills varies 

by mill type. Pulp mills are located primarily in regions 

of the country where trees are harvested from natural 

stands or tree farms—that is, in the Southeast, Northwest, 

Northeast and North Central regions. Pulp mills that 

process recycled fi ber are generally located near sources 

of waste paper. Paper mills are located near pulping 

operations or near converting markets. The distribution 

of paperboard mills refl ects the location of manufacturing 

facilities in general, since manufacturing operations are 

the primary market for paperboard products (EPA, 2002).

Emissions

Table 8.1 summarizes the emissions generated by the pulp 

and paper sector based on EPA’s 1999 National Emissions 

Inventory. Mills that are primarily engaged in pulp, 

paper or paperboard manufacturing are the dominant 

source of PM2.5, SO2 and NOx emissions within the 

sector. Converting facilities, which produce a wide range 

of products like envelopes and paper bags, account for 3 

percent or less of emissions. (Note that some integrated 

mills, classifi ed as paper or paperboard mills, may also 

manufacture converted products.) In terms of the many 

processes involved in producing paper, recovery boilers 

and power boilers are the dominant source of emissions 

within the sector, as illustrated by Table 8.2, which shows 

NOx and SO2 emissions reported by the Fraser NH LLC 

integrated pulp and paper mill in Berlin, New Hampshire.

Table 8.1

Pulp and Paper Sector Emissions

Process Type

PM2.5 SO2 NOx

Tons/Year

Percent 

of Sector 

Emissions Tons/Year

Percent 

of Sector 

Emissions Tons/Year

Percent 

of Sector 

Emissions

Pulp & paper mills 78,798 77% 372,704 81% 239,862 78%

Paperboard mills 20,222 20% 77,964 17% 61,625 20%

Converted paper 

and paperboard 

products 

manufacturing

3,079 3% 7,199 2% 6,982 2%

Total 102,099 100% 457,868 100% 308,470 100%

Source: EPA, 2005

Table 8.2

Sample Pulp Mill Emissions Inventory: Fraser 

NH LLC, Berlin, New Hampshire (2003)a

Device SO2 tons (%) NOx tons (%)

Recovery boiler 43 (2%) 226 (33%)

Hog-fuel boilerb 8 (<1%) 124 (18%)

Five oil-fi red boilers 1,819 (87%) 312 (46%)

Lime kiln 226 (11%) 17 (3%)

Other 5 (<1%) 2 (<1%)

a. PM2.5 emissions were not reported.

b. Hog-fuel is waste wood (e.g., bark, shavings, sawdust) used 

for energy production. 

Source: New Hampshire DES, 2005
110 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

The Paper Making Process

The fi rst step in the paper making process is the 

preparation of the raw material inputs: (1) debarking and 

chipping newly harvested wood; or (2) preparing recycled 

products for pulping. Wood chipping operations, including 

chip conveyor systems, produce fugitive PM emissions; 

however, there is limited information on the particle sizes 

or quantity of emissions from wood chipping (Davis, 2000; 

Sharifsoltani, 2003).

After chipping wood or preparing recycled products, 

manufacturers begin the process of pulping (breaking 

down the wood into fi bers). Within the pulp and paper 

industry, the pulping process is the main source of air 

emissions. The process is based on chemical wood 

pulping or mechanical wood pulping. There are three 

types of chemical pulping: kraft (bleached or unbleached), 

acid sulfate pulping and semichemical pulping. Figure 

8.1 presents the share of pulp making by pulp production 

process in 2000 (EPA, 2002). The kraft pulping process, 

discussed below, is the dominant pulping process and is 

used for more than 80 percent of overall pulp production 

(on a tonnage basis) in the U.S. (EPA, 2002).

During the actual paper making process, manufacturers 

spread a wet mixture of pulp onto screens and use vacuums 

and gravity to remove water. Manufacturers then pass the 

fi bers through rollers and dryers that compress the material 

into sheets and remove the remaining moisture (EPA, 

2002). Emissions are mainly in the form of water vapor, 

with little or no PM emissions. NOx or SO2 emissions may 

be generated by the dryers, depending on the type of fuel 

used for heating. These emissions are small because of the 

low heat levels needed and the large amounts of air used in 

the process (EPA, 2002; Davis, 2000). 

Once the paper has been spread and dried, the converting 

process—which involves the cutting, gluing or folding 

of paper products into fi nal form—begins. Emissions 

from these processes result primarily from the indirect 

emissions associated with energy consumption. Emissions 

may result from the burning of fossil fuels on-site to 

generate hot air for drying or heating, but there appear to 

be no data on these emissions (Davis, 2000).

Since pulping is the primary source of PM, SO2 and NOx

emissions, the remainder of this chapter focuses on the 

pulping process.

Kraft Pulping

The chemical processes that form the basis for kraft 

pulping have not changed fundamentally since the patent 

offi ce issued a patent for this process in 1884 (EPA, 2002). 

Figure 8.2 provides an overview of a kraft pulping mill 

with an integrated paper making system. The descriptions 

of the kraft process in this section focus on sources of air 

emissions, the majority of which occur in the chemical 

recovery system. For a more detailed description of the 

kraft pulping process see Chapter 18 (Wood Processing 

Industry) in Davis, 2000; or Smook, Handbook for Pulp 

and Paper Technologists, 2nd Edition, 1992, which EPA 

recommends (EPA, 2002).

As noted, there are four signifi cant emissions sources 

within the kraft pulping process: recovery furnaces (or 

recovery boilers), SDTs, lime kilns and power boilers. 

As shown in Figure 8.3, all of these sources— except 

for power boilers—are directly or exclusively involved 

in the chemical recovery system. (Power boilers supply 

energy to systems throughout the facility.) The chemical 

recovery system collects waste liquids and gases from the 

chemical pulping process and treats them before recycling 

them back into the chemical pulping process or removing 

them from the process. Chemical recovery is used in 

all of the chemical pulping processes (kraft, sulfi te and 

semichemical), reducing discharges to the environment 

and reducing operating costs (EPA, 2002). Note that this 

section focuses on the chemical recovery system in the 

kraft process; semichemical and sulfi te chemical recovery 

processes are different and are treated separately.

Kraft mills produce pulp from wood chips or recycled 

products by digesting them in a solution called white 

liquor (Davis, 2000). One of the byproducts of this 

digestion is weak black liquor. This liquor contains the 

pulping chemicals and lignin from the trees. Weak black 

liquor (about 15 percent solids) is concentrated into heavy 

black liquor (usually 68–75 percent solids) by evaporation. 

There are two evaporator types: direct contact evaporators 

(DCEs) and non-direct contact evaporators (NDCEs). 

DCEs—used in older furnaces—use direct contact 

with the hot furnace fl ue gas to heat the weak black 

Fig. 8.1 Production by Pulping Process, 2000

Kraft (bleached)

49%

Sulfi te

2%

Mechanical

10%

Semichemical

6%

Kraft 

(unbleached)

33%

Source: EPA, 2002
 Chapter 8 - Pulp and Paper Industry 111

PULPING

Wood Water

BLO

Tank

Heavy black liquor storage tank

Evaporators

Pulp

(to paper

machine)

Weak black liquor

Slaker

Causticizers

Lime

Scrubber

or

ESP

Green liquor Lime

mud

Weak wash

Green liquor

clarifier

Mix

tank

SDT

White liquor

clarifier

Mud

washer

Weak

liquor

storage

White liquor

Digesters,

Blow tanks,

Washer,

etc.

White liquor

Liquor

Flue gas

HAP emission sources

addressed by Pulp and

Paper Combustion

Sources NESHAP

ESP Chemical

ash tank

DOE

Recovery

furnace

Scrubber

Lime Kiln

Turpentine

Recovery

System

Wood Chips

Digester System

Chemical Recovery System

Weak Black Liquor 

Storage Tank

Screening

System

Decker

System

Oxygen

Delignification

System

Knotter System

Papermaking System Reliners/Cleaners Bleaching System

Pulp Washing System

Evaporator

System

Fig. 8.2 Overview of Kraft Pulping with Paper Making

Fig. 8.3 Chemical Recovery System Details

Source: EPA, 1998

Source: EPA, 1998
112 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

liquor. In newer furnaces, the liquor is concentrated in 

closed NDCEs. These have the advantage of preventing 

emissions of sulfur compounds (total reduced sulfur or 

TRS) that are stripped from the liquor by direct contact 

with the fl ue gas.2

Recovery Furnaces and Power Boilers 

Pulp facilities burn concentrated black liquor in recovery 

furnaces to produce energy and recover sodium and sulfur. 

Recovery furnaces are similar in design to fossil fuelfi red boilers, but are several times larger than a typical 

industrial boiler. Nevertheless they have comparable 

output as a result of the relatively low heating value of the 

black liquor (about 6,000 British thermal units per pound 

(Btu/lb)). Sodium and sulfur compounds are collected as 

2. Note that TRS has historically been the focus of regulation at kraft 

pulp mills (along with particulates) because it is the source of the strong 

“rotten egg” odor frequently associated with the pulp and paper industry. TRS compounds are a byproduct of the reaction between the wood 

and the white liquor.

molten smelt from the bottom of the recovery furnace.

Table 8.3 reports the estimated emissions of a recovery 

furnace. The PM emissions rates assume that an 

electrostatic precipitator (ESP) is installed. The type of 

evaporator used in the process infl uences emissions from 

the recovery furnaces. About 90 percent of PM emissions 

consist of PM10, and of this subset about 50 percent of 

particles are smaller than 1 micrometer (μm) in diameter 

(Davis, 2000). Note that NDCEs do not appear to 

signifi cantly reduce PM, SO2 or NOx emissions. NDCEs 

are preferred over DCEs because of their impact on TRS, 

not on PM, SO2 and NOx emissions.

SO2 concentrations in the stack gases from a recovery 

furnace average between 0 and 500 parts per million 

(ppm) (Davis, 2000). SO2 emissions from recovery 

furnaces are highly variable and depend on liquor 

properties, combustion patterns and furnace design. NOx

concentrations in the stack gases average between 50 and 

100 ppm (Davis, 2000).

The energy generated by the recovery furnace is used 

to power the facility; however, supplemental energy is 

generally required to power all processes. Industry-wide, 

combustion of spent liquor solids in the recovery furnace 

makes up about 40 percent of overall energy requirements, 

as shown in Table 8.4. Manufacturers make up for the 

shortfall with fossil fuel- and wood-fi red boilers. Table 

8.4 shows that natural gas is the largest fuel source for the 

non-recovery boilers (power boilers), followed by wood, 

coal and fuel oil. Emissions factors for industrial boilers 

burning these types of fuels are discussed in Chapter 6, 

Industrial and Commercial Boilers.

The total boiler capacity of the pulp and paper sector, 

including recovery and power boilers, is estimated at 

376,000 million British thermal units per hour (MMBtu/

hr), or 25 percent of total industrial boiler capacity in the 

U.S. (Energy and Environmental Analysis, 2005). The 

sector is also the largest consumer of boiler fuel within the 

Table 8.3

Emissions from Kraft Recovery Furnaces

Pollutant DCE Kraft Recovery Furnace NDCE Kraft Recovery Furnace

Emissions Range

(lb/ton BLS)

Emissions Mean

(lb/ton BLS)

Emissions Range

(lb/ton BLS)

Emissions Mean 

(lb/ton BLS)

PM 0.41–0.98 0.45 0.31–1.66 1.04

SO2 0.025–10.8 2.06 0.01–54.1 2.63

NOx 1.06–2.44 1.45 0.63–2.30 1.20

BLS = black liquor solids

Source: Davis, 2000

Table 8.4

Estimated Energy Sources 

for the U.S. Pulp and Paper Industry

Energy Source Percent (1999)

Purchased steam 1.5

Coal 12.5

Fuel oil 6.3

Natural gas 17.6

Other purchased energy 6.7

Waste wood and wood 

chips and bark

13.5

Spent liquor solids 40.3

Other self-generated power 1.6

Total 100

Source: EPA, 2002
 Chapter 8 - Pulp and Paper Industry 113

industrial sector, consuming more than 2,200 trillion Btu 

per year (Energy and Environmental Analysis, 2005). This 

places the pulp and paper sector ahead of the chemical, 

petroleum refi ning, and primary metals industries in terms 

of boiler fuel consumption.

Smelt Dissolving Tank

The molten smelt collected from the bottom of the recovery 

furnace’s combustion chamber contains sodium and sulfur 

from the combusted liquor. Molten smelt is quenched with 

water in the SDT to form green liquor, which is a solution 

of sodium sulfi de and sodium carbonate (EPA, 2002). The 

steam produced in the quenching process is a source of PM 

emissions. PM is usually removed with a wet scrubber, 

such as a venturi scrubber (Davis, 2000). (Chapter 5, 

Boiler Technologies, includes more information on wet 

scrubbers.) Table 8.5 summarizes the controlled emissions 

rates of an SDT.

Lime Kilns 

Once the smelt has been treated in the SDT, further 

processing is required to produce white liquor and calcium 

carbonate (Davis, 2000). The calcium carbonate is sent to 

a lime kiln, where it is converted into quicklime for reuse 

in the white liquor recycling process. Like SDTs, lime 

kilns are usually controlled with venturi scrubbers. Kraft 

mill lime kilns are large rotary kilns, which typically fi re 

either natural gas or residual oil (Davis, 2000). Table 8.6 

provides emissions estimates for lime kilns.

Acid Sulfi te Pulping

Acid sulfi te pulping operations in the U.S. produce less 

than 2 percent of total pulp. Use of the process has been 

declining for decades; in 1999 there were only 11 mills 

in the U.S. using sulfi te pulping (Davis, 2000) and fewer 

than fi ve mills in 2005 (Lockwood-Post Directory, 2005). 

Sulfi te pulping involves digesting wood chips with an 

acidic solution. Some sulfi te operations use chemical 

recovery with evaporators and recovery furnaces.

SO2 emissions are a signifi cant concern from acid sulfi te 

pulping; 10–70 pounds of SO2 can be released per ton of 

pulp if care is not taken when excess gases are released 

from the digester (Davis, 2000). Additional SO2 can 

be released during the washing process if gases are not 

collected and redirected to a scrubber. Uncontrolled 

emissions from washing are normally 1–4 pounds per 

ton (lb/ton) of pulp, but can be as high as 16 lb/ton (Davis, 

2000).

Semichemical Pulping

Semichemical pulping is used to produce approximately 

6 percent of total pulp in the U.S. (EPA, 2002); 

approximately ten plants rely on the process (LockwoodPost Directory, 2005). This pulping process involves 

partial chemical digestion of the wood by using either a 

lower temperature, shorter cooking time or more dilute 

liquor than in a conventional chemical process. A neutral 

sulfi te digesting liquor is commonly used for partial 

chemical digestion, followed by grinding of the wood 

chips in a refi ner. Chemical recovery is not practiced at 

any of the semichemical operations in the U.S.

The major process difference between chemical pulping 

and semichemical pulping is that semichemical pulping 

uses lower temperatures, more dilute cooking liquor or 

shorter cooking times, and mechanical disintegration for 

fi ber separation (EPA, 2002).

Mechanical Pulping

Mechanical pulping operations in the U.S. produce 10 

percent of total pulp (EPA, 2002). Despite its name, 

mechanical pulping can involve some steaming or sulfi te 

softening of the wood prior to the grinding operation. 

Mechanical pulping typically results in high pulp yields, 

up to 95 percent, as compared to chemical pulping yields 

of 45–50 percent, but energy usage is also high. To offset 

its structural weakness, mechanical pulp is often blended 

with chemical pulp (EPA, 2002). There are approximately 

24 mechanical pulp mills in the U.S. (Lockwood-Post 

Directory, 2005).

Table 8.6

Emissions from Lime Kilns

Pollutant

Emissions Range

(lb/ton CaOa)

Emissions Mean

(lb/ton CaOa)

PMb 0.84–4.0 1.82

SO2 0.01–1.63 0.23

NOx 0.08–9.0 2.19

a. CaO, reburned lime product

b. After venturi scrubber

Source: Davis, 2000

Table 8.5

SDT Emissions

Pollutant

Emissions Range

(lb/ton BLSa)

Emissions Mean

(lb/ton BLSa)

PMa 0.04–0.18 0.13

SO2 ND–0.075c 0.016

NOx ND–0.151c 0.033

BLS = black liquor solids

ND = not detected

a. After a venturi scrubber

Source: Davis, 2000
114 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Emissions Control Opportunities

As discussed in the previous section, the primary 

sources of PM2.5, SO2 and NOx emissions from pulp and 

paper mills are recovery furnaces, SDTs, lime kilns and 

power boilers. Chapter 5, Boiler Technologies, discusses 

emissions control technologies for power boilers that burn 

coal, natural gas, oil or wood.

Controlling PM Emissions

Recovery furnaces rely on an ESP or a combination of an 

ESP and wet scrubber to control PM emissions. Most PM 

emissions from lime kilns and SDTs are controlled with 

wet scrubbers—typically, venturi scrubbers (Davis, 2000). 

Opportunities exist to reduce current PM emissions levels 

by upgrading or replacing older wet scrubbers or ESPs 

(NESCAUM, 2005). For example, on recovery furnaces, 

older model ESPs have collection effi ciencies close to 

90 percent, while newer model ESPs have collection 

effi ciencies greater than 99 percent (Davis, 2000).

The cost of retrofi tting a recovery furnace with an ESP 

is heavily infl uenced by site-specifi c factors. Table 8.7 

provides one estimate of the costs for a unit equipped with 

DCE and a unit equipped with NDCE. Capital costs range 

from $18.4–$29.3 million.

Lime kilns installed in the past ten years are likely to have 

an ESP control system. Emissions from older units can 

be reduced by replacing wet scrubbers with ESPs. Table 

8.8 shows estimated costs for implementing this type of 

replacement to meet the 0.01 grains per dry standard cubic 

foot limit set in the recent MACT standard (described 

below).

Controlling SO2 Emissions

Other than power boilers, recovery furnaces are the main 

source of SO2 emissions from pulp and paper mills. In 

general, recovery furnaces are designed to maximize 

sulfur recovery while minimizing sulfur air emissions. 

This is accomplished by operating an overall reducing 

atmosphere in the combustion zone, producing sodium 

sulfi de from the sulfate in the black liquor rather than SO2 

(North Carolina DENR, 2000).

Compared to the more traditional fuels burned in power 

boilers (i.e., natural gas, coal, wood and oil), the black 

liquor solids burned in the recovery furnace can have 

widely varying sulfur content. This results in variable SO2

emissions, making control diffi cult.

Despite this diffi culty, some facilities have successfully 

lowered SO2 emissions by reducing the sulfur content 

of the black liquor before combustion and by regulating 

temperatures in the furnace to minimize SO2 formation 

(Davis, 2000). Only one example of a pulp mill utilizing 

a wet scrubber for SO2 control was identifi ed (North 

Carolina DENR, 2000). Table 8.9 presents estimated costs 

for installing scrubbers that reduce emissions to between 

10 and 50 ppm; however, costs are reported to be highly 

site specifi c.

Another source of SO2 emissions is the combustion of TRS. 

As briefl y mentioned in the kraft process description, the 

pulping process results in the formation and release of TRS 

(a pollutant that is well known for its “rotten egg” odor). 

One control option for TRS is collection and combustion. 

If the combustion is uncontrolled, this option can result 

in SO2 emissions of about 5.7 pounds per air-dried ton of 

unbleached pulp. When TRS is burned in lime kilns or 

Table 8.8

Estimated Lime Kiln ESP Retrofi t Costs

Lime Kiln 

Characteristicsa Capital Cost O&M (annual)

270 CaO/day $3.4 million $0.2 million

a. CaO, reburned lime product

Source: NESCAUM, 2005

Table 8.9

Estimated Recovery Furnace SO2 Scrubber 

Retrofi t Costs

Furnace 

Characteristics Capital Cost O&M (annual)

NDCE, 3.7 MMlb 

BLS/day

$12.8 million $1.6–$1.8 million

DCE, 1.7 MMlb 

BLS/day

$8 million $1.1–$1.3 million

BLS = black liquor solids

Source: NESCAUM, 2005

Table 8.7

Estimated Recovery Furnace ESP Retrofi t 

Costs

Furnace 

Characteristics Capital Cost O&M (annual)

NDCE, 3.7 MMlb 

BLS/day

$29.3 million $1.9 million

DCE, 1.7 MMlb 

BLS/day

$18.4 million $1.2 million

BLS = black liquor solids

Source: NESCAUM, 2005
 Chapter 8 - Pulp and Paper Industry 115

wood residue-fi red boilers, the lime or bark ash alkalinity 

captures a signifi cant portion of the SO2. Another option 

is to remove SO2 with alkaline scrubbers (Davis, 2000).

Acid sulfi te pulping is used at a declining number of 

pulping operations, but it can emit large amounts of SO2

per ton of pulp. Raising the pH of the digester before 

releasing excess gas reduces the amount of SO2 released. 

Alternatively, SO2 can be scrubbed out using an alkaline 

solution (with recovery of up to 97 percent) (Davis, 2000).

Controlling NOx Emissions

Apart from the power boilers, lime kilns and recovery 

furnaces are the primary sources of NOx emissions from 

pulp and paper mills; however, options to reduce these 

emissions are limited. Staged combustion can reduce 

NOx emissions, but care must be taken because changes in 

fi ring patterns may increase SO2 emissions (Davis, 2000). 

Selective non-catalytic reduction (SNCR) and selective 

catalytic reduction (SCR) technologies for recovery 

furnaces have been investigated but have been determined 

not to be technically feasible. Further, low-NOx burners 

appear to adversely affect effi ciency and energy usage 

(NESCAUM, 2005). 

Several permits were reviewed to determine whether NOx

controls have been applied to lime kilns and recovery 

furnaces in the pulp and paper industry. A best available 

control technology (BACT) analysis for a proposed lime 

kiln evaluated the feasibility of low-NOx burners, fl ue 

gas recirculation, oxidation/reduction scrubbing, SCR, 

SNCR and non-selective catalytic reduction, concluding 

that none of these options is technically feasible for lime 

kiln NOx emissions control. Rather, the regulatory agency 

concluded that “good design and operation practices” 

constitute BACT, and established a NOx limit of 175 ppm 

at 10 percent oxygen (Georgia DNR, 2003).

Similarly, a BACT analysis for a kraft recovery furnace 

concluded that SCR and SNCR were both technically 

infeasible for recovery furnace NOx emissions control. 

The regulatory agency determined that combustion 

controls (staged combustion) constitute BACT for the 

recovery boiler, and reported that the RACT/BACT/LAER 

Clearinghouse includes combustion controls as BACT for 

recovery furnaces with NOx emissions ranging from 75–

120 ppm (North Carolina DENR, 2000).

Regulatory Authority

As indicated in the more detailed discussion of the Clean 

Air Act in Chapter 4, states and the federal government 

share responsibility for regulating criteria pollutants 

(e.g., PM2.5, SO2, NOx) from stationary sources like those 

operating at pulp and paper mills. The federal government 

has more of the burden of regulating toxic air pollutants, 

but—for both criteria pollutants and air toxics—state and 

local agencies are free under federal law to adopt more 

stringent standards than the Clean Air Act requires. 

This section describes federal standards that apply under 

the Clean Air Act to emissions from pulp and paper mills.

Reasonably Available Control Technology

State Implementation Plans (SIPs) for areas that are in 

nonattainment of federal ambient air quality standards 

must include Reasonably Available Control Technology 

(RACT) requirements for new and existing sources. 

RACT standards are non-binding federal guidelines; 

for volatile organic compounds (VOCs), the guidelines 

are known as Control Technique Guidelines (CTGs). 

Table 8.10

NSPS for Kraft Pulp Mills (40 CFR §§60.280, et seq. (subpart BB))a

Source Particulate Matter Limit Opacity Limit

Recovery furnace 0.10 g/dscm 

(0.044 gr/dscf)b,c

35%

SDT 0.1 g/kg 

(0.20 lb/ton) BLS

NA

Lime kiln (gaseous fossil fuel such as natural gas) 0.15 g/dscm 

(0.066 gr/dscf)d

NA

Lime kiln (liquid fuel such as oil) 0.30 g/dscm 

(0.13 gr/dscf)d

NA

BLS = black liquor solids

a. The kraft NSPS also include TRS limits for various sources, including recovery furnaces, lime kilns, and SDTs.

b. g/dscm stands for “grams per dry standard cubic meter;” gr/dscf stands for “grains per dry standard cubic feet.”

c. Corrected to 8 percent oxygen

d. Corrected to 10 percent oxygen
116 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Regional Haze/Best Available Retrofi t 

Technology

Under the regional haze program, Best Available Retrofi t 

Technology (BART) requirements for the control of PM2.5

and PM2.5-precursor emissions apply to certain large 

sources (in both attainment and nonattainment areas) that 

began operation between 1962 and 1997. The 26 source 

categories subject to BART requirements include kraft 

pulp mills. However, states have not yet developed BART 

rules under the regional haze program.

New Source Review/Prevention of Signifi cant 

Deterioration

New Source Review (NSR) requirements apply to new 

and modifi ed large stationary sources in nonattainment 

areas, while Prevention of Signifi cant Deterioriation 

(PSD) requirements apply to large stationary sources 

in attainment areas. Under these programs, plants in 

nonattainment areas are required to implement Lowest 

Achievable Emission Rate (LAER) controls and plants in 

attainment areas are required to implement BACT. Neither 

BACT nor LAER standards are codifi ed because they are 

intended to refl ect technology advancements as they occur.

Several permits were evaluated to determine what is 

generally considered BACT for lime kilns and recovery 

boilers. 

As indicated above, “good design and operation practices” 

were determined to constitute BACT for lime kiln NOx

emissions control (Georgia DNR, 2003). Combustion 

controls (staged combustion) were determined to constitute 

Guidelines known as Alternative Control Techniques 

(ACTs) outline the control technologies that are available 

to address NOx emissions from specifi c source sectors, but 

do not specify actual RACT limits. There are no sectorspecifi c ACTs or CTGs for SO2, PM10 or PM2.5.

EPA has not published ACT guidelines for pulp and paper 

mills.

New Source Performance Standards

New Source Performance Standards (NSPS) typically 

apply, in both attainment and nonattainment areas, to 

new and reconstructed sources within specifi c source 

categories. 

The requirements of 40 CFR §§60.280, et seq. (subpart 

BB) apply to kraft pulp mills that commence construction, 

modifi cation or reconstruction after September 24, 1976. 

The NSPS standards do not apply to semichemical, 

mechanical or sulfi te mills, which account for only a small 

segment of the industry’s emissions. The kraft NSPS limit 

PM from recovery furnaces, SDTs and lime kilns.

The NSPS for kraft pulp mills appear in Table 8.10.

Power boilers used to generate electricity and steam at pulp 

and paper facilities are subject to the NSPS for industrial 

boilers (40 CFR §§60.40b, et seq. (subpart Db) and 40 

CFR §§60.40c, et seq. (subpart Dc)), discussed in Chapter 

6, Industrial and Commercial Boilers. Newer boilers are 

subject to limits for PM, SO2 and NOx emissions under 

these rules.

Table 8.11

MACT Standards for Chemical Recovery Combustion Sources at Kraft Pulp Mills (40 CFR §§63.860, et 

seq. (subpart MM))a

Facility Type Source

PM Emissions Limit

Existing Sourceb New Source

Kraft pulp mill Recovery furnace 0.10 g/dscm

(0.044 gr/dscf)c,d

0.034 g/dscm

(0.015 gr/dscf)e

SDT 0.10 kg/Mg

(0.20 lb/ton) BLS

0.06 kg/Mg

(0.12 lb/ton) BLS

Lime kiln 0.15 g/dscm 

(0.064 gr/dscf)e

0.023 g/dscm

(0.01 gr/dscf)e

BLS = black liquor solids

a. These standards also apply to soda, sulfi te and stand-alone semichemical pulp mills.

b. As an alternative to the PM emissions limits for existing kraft pulp mills, each owner or operator of a kraft pulp mill may establish PM 

emissions limits for each existing kraft recovery furnace, SDT, and lime kiln that operates 6,300 hours or more per year using a methodology 

described in Subpart MM. Under the methodology, the combined emissions from the recovery furnace, SDT, and lime kiln cannot exceed 

the combined emissions limits. Limits established using this methodology are not allowed to exceed applicable NSPS limits. 

c. g/dscm, gram per dry standard cubic meter; gr/dscf, grains per dry standard cubic feet

d. Corrected to 8 percent oxygen

e. Corrected to 10 percent oxygen
 Chapter 8 - Pulp and Paper Industry 117

BACT for recovery boiler NOx emissions control 

(North Carolina DENR, 2000). The Washington State 

Department of Ecology determined that good combustion 

practices (with an emissions limit of 95 ppm) constituted 

BACT for recovery furnace NOx emissions control 

(Washington DEC, 2003).

In terms of SO2, “no control” was determined to constitute 

BACT for a recovery boiler because of the high cost per 

ton removed with the application of a wet scrubber (North 

Carolina DENR, 2000; Georgia DNR, 2003). Recent 

BACT determinations are reported to limit SO2 emissions 

to between 50 and 300 ppm (NESCAUM, 2005).

In terms of PM, the Georgia Department of Natural 

Resources concluded that an ESP with a 99.8 percent 

control effi ciency constituted BACT for recovery boiler 

PM10 emissions control (Georgia DNR, 2003).

Maximum Achievable Control Technology

Maximum Achievable Control Technology (MACT) 

standards address emissions of hazardous air pollutants 

(HAPs) from new and existing sources in identifi ed 

industry categories. They apply in both attainment and 

nonattainment areas to sources with potential emissions of 

10 tons per year of a single HAP or 25 tons per year of 

combined HAPs.

Under 40 CFR §§63.860, et seq. (subpart MM), PM 

emissions from kraft and sulfi te pulp mills are regulated as 

a surrogate for HAPs. The subpart was developed by EPA 

as part of a “cluster rule” that covered both air emissions 

and water discharges from the pulp and paper industry. 

It includes standards for combustion sources at kraft and 

sulfi te mills.

The owner or operator of an existing affected source or 

process unit must comply with the requirements in Table 

8.11 no later than March 13, 2004. The owner or operator 

of a new affected source that has an initial start-up date 

after March 13, 2001 must comply with the requirements 

immediately upon start-up.

The new source MACT standards in Table 8.11 for recovery 

furnaces and lime kilns are based on the emissions levels 

achieved by units equipped with ESPs, while the standards 

for SDTs are based on emissions levels attained by units 

with wet scrubbers (EPA, 2001).

Clean Air Interstate Rule

In March 2005, EPA promulgated the Clean Air Interstate 

Rule (CAIR), which aims to address pollution transport 

that contributes to the nonattainment of eight-hour ozone 

and PM2.5 air quality standards throughout the eastern 

U.S. States can choose how to achieve these reductions, 

but it is expected that most, if not all, states will opt to 

cap emissions according to budgets established by EPA 

and participate in EPA-administered emissions trading 

programs. None of the sources operating at pulp and paper 

mills that are discussed here can be included in any of the 

federal CAIR trading programs without disqualifying the 

state from participation in the federal trading regimes.

State and Local Policy Measures

With the updated MACT standards, EPA anticipates a 

national reduction in PM emissions and a reduction in 

SO2 emissions as a secondary benefi t of the PM control 

measures (Telander, 2002). While these reductions will 

reduce PM2.5 emissions, there are additional measures 

states might consider.

Update PM Emissions Limits

There are MACT standards for PM emissions from 

recovery furnaces, lime kilns and SDTs. These standards 

are 40 to 85 percent more stringent for new sources than 

they are for existing sources. State and local regulators 

should evaluate the feasibility of requiring existing 

sources to meet more stringent standards. For example, 

at existing facilities, upgrades to ESPs and replacement 

of wet scrubbers with ESPs can signifi cantly reduce PM 

emissions. Older model ESPs on recovery furnaces have 

collection effi ciencies close to 90 percent, while newer 

model ESPs have collection effi ciencies greater than 99 

percent.

Limit SO2 Emissions from Kraft Pulp Mills

As described in the section of this chapter that discusses 

regulatory authority, the kraft NSPS limit PM and TRS 

emissions, but not SO2. However, some states and local 

areas, such as Washington and the Lane Regional Air 

Pollution Authority in Oregon, have established SO2

emissions limits for recovery furnaces, lime kilns and 

other combustion devices at kraft pulp mills (WAC, 1991a; 

LRAPA, 2005).

States have also used BACT determinations to limit SO2

emissions from individual kraft mills, with limits ranging 

from 50 to 300 ppm (NESCAUM, 2005). 

Limit SO2 Emissions from Sulfi te Pulp Mills

States with sulfi te pulping operations should consider 

limiting SO2 emissions from these facilities. (In 2005, 

fewer than fi ve sulfi te pulping facilities remained in 

the U.S.) For example, Washington State limits the SO2

emissions from sulfi te pulp mills as summarized in Table 

8.12.
118 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Power Boilers

Power boilers are a major source of PM2.5, SO2 and NOx

emissions within the pulp and paper industry, and several 

options are available for reducing their emissions, as 

discussed in Chapter 6, Industrial and Commercial Boilers. 

In contrast, sources indicate that many of the technologies 

that are used to control fossil fuel boilers, such as SCR, are 

not feasible for the control of NOx and SO2 emissions from 

lime kilns and recovery furnaces (NESCAUM, 2005). 

At the same time, however, there are wide variations in 

the emissions generated by these sources. For example, 

NESCAUM reports SO2 emissions from kraft recovery 

furnaces ranging from almost 0 to 300 ppm. 

State and local agencies might consider facility-wide PM2.5, 

NOx and SO2 limits for pulp and paper facilities, rather than 

simply limiting power boiler emissions, which appear to be 

the most feasible to control. This facility-wide approach 

would increase the fl exibility that companies have to meet 

their compliance obligations, while reducing the overall 

costs of compliance and the aggregate emissions from 

these sources.

References

Davis, W., Air & Waste Management Association. Air 

Pollution Engineering Manual: Second Edition, 2000.

Energy and Environmental Analysis, Inc. Characterization 

of the U.S. Industrial Commercial Boiler Population, May 

2005.

Environment Canada and the Canadian Council of 

Ministers of Environment. Multi-pollutant Emission 

Reduction Analysis Foundation (MERAF) for the Pulp 

and Paper Sector, prepared by AMEC Forest Industry 

Consulting, September 2002. www.ccme.ca/assets/pdf/

pulp_paper_fi nal_meraf_e.pdf.

Georgia Department of Natural Resources (DNR). 

Prevention of Signifi cant Air Quality Deterioration 

Review of Weyerhaeuser—Flint River Operations Located 

in Macon County, Georgia (Preliminary Determination 

SIP Permit Application No. 14050), March 2003. www.

air.dnr.state.ga.us/airpermit/permits/1930013/psd14051/

19300013pd.pdf.

Lane Regional Air Pollution Authority (LRAPA). 

“Prohibited Practices and Control of Special Classes of 

Industry: Kraft Pulp Mills,” Title 33 §33-070, LRAPA 

Rules and Regulations, accessed December 12, 2005, 

from: www.lrapa.org/rules. 

Lockwood-Post Directory. North American Online Edition,

accessed September 20, 2005, from: http://store.paperloop.

com/cgi-bin/paperloop/NA.html.

New Hampshire Department of Environmental Services 

(DES), Air Resources Division. “2003 Emission 

Calculations,” 2003 Emission Based Fees Invoice: Fraser 

NH, LLC., October 5, 2005.

North Carolina Department of Natural Resources (DENR). 

Prevention of Signifi cant Deterioration—Preliminary 

Determination for Weyerhaeuser Company, Plymouth 

Pulp and Paper Mill, September 2000.

Northeast States for Coordinated Air Use Management 

(NESCAUM). Assessment of Control Technology Options 

for BART-Eligible Sources: Steam Electric Boilers, 

Industrial Boilers, Cement Plants and Paper and Pulp 

Facilities, March 2005. http://bronze.nescaum.org/

committees/haze/BART_Control_Assessment.pdf.

Sharifsoltani, Roya, Oklahoma Department of 

Environmental Quality. Memorandum Regarding 

Evaluation of Permit Application No. 97-057-C (PSD) (M2), Weyerhaeuser Company Valliant Paper Mill, August 

26, 2003. www.deq.state.ok.us//AQDnew/permitting/

permissue/97057-cp2.doc.

State and Territorial Air Pollution Program Administrators 

and the Association of Local Air Pollution Control 

Offi cials (STAPPA and ALAPCO). Reducing Greenhouse 

Gases & Air Pollution: A Menu of Harmonized Options, 

Final Report, October 1999.

Telander, J., to Docket Number OAR-2002-0045 (A-94-67). 

Table 8.12

Washington State Emissions Guidelines for 

Sulfi te Pulp Mills

Source SO2 Limit

Sulfi te pulp mill with 

incineration

10 g/kg (20 lb/ton) air dried, 

unbleached pulp

Sulfi te pulp mill without 

incineration

2 g/kg (4 lb/ton) air dried, 

unbleached pulp

Blow system 0.1 g/min (15 min average)/

kg (0.2 lb/min/ton) air dried, 

unbleached pulp

Recovery system and 

acid plant

800 ppm (hourly average)

Recovery systems 

after Jan 24, 1972

300 ppm (hourly average)

Emissions unit (except 

recovery system), blow 

system, or acid plant

1000 ppm (hourly average) @ 

7% oxygen

Source: WAC, 1991b
 Chapter 8 - Pulp and Paper Industry 119

Memorandum regarding “Summary of Public Comments 

and Responses on the Proposed NESHAP for Chemical 

Recovery Combustion Sources at Kraft, Soda, Sulfi te, and 

Stand-Alone Semichemical Pulp Mills,” November 2002. 

http://docket.epa.gov/edkpub/index.jsp.

U.S. Department of Energy (DOE), Industrial Technologies 

Program. Forest Products: Industry of the Future, Fiscal 

Year 2004 Annual Report, February 2005. www.eere.

energy.gov/industry/about/pdfs/forest_fy2004.pdf.

U.S. Environmental Protection Agency (EPA), Offi ce 

of Air Quality Planning and Standards. Pulp and Paper 

NESHAP: A Plain English Description (EPA-456/R98-008), November 1998. www.epa.gov/ttn/uatw/pulp/

pulppg.html.

U.S. Environmental Protection Agency (EPA). 1999 

National Emissions Inventory Final Version 3.0, obtained 

from EPA staff, October 2005. www.epa.gov/ttn/chief/net/

1999inventory.html.

U.S. Environmental Protection Agency (EPA). “National 

Emission Standards for Hazardous Air Pollutants for 

Chemical Recovery Combustion Sources at Kraft, Soda, 

Sulfi te, and Stand-Alone Semichemical Pulp Mills; Final 

Rule,” Federal Register 66(9): 3180, January 12, 2001. 

www.epa.gov/ttn/oarpg/t3/fr_notices/pp_fr4.pdf.

U.S. Environmental Protection Agency (EPA). EPA Offi ce 

of Compliance Sector Notebook Project: Profi le of the 

Pulp and Paper Industry, Second Edition, November 

2002. www.epa.gov/compliance/resources/publications/

assistance/sectors/notebooks/pulp.html.

Washington Administrative Code (WAC). Emission 

Standards for Kraft Pulp Mills (173-405-040), February 

19, 1991. www.mrsc.org/. (1991a)

Washington Administrative Code (WAC). Emission 

Standards for Sulfi te Pulping Mills (173-410-040), 

February 19, 1991. www.mrsc.org/. (1991b)

Washington State Department of Ecology (DEC). Final 

Approval of Prevention of Signifi cant Deterioration 

Application: Longview Fiber Company (No. 01-03), 2003. 

www.ecy.wa.gov/programs/air/psd/PSD_PDFS/PSD0103_

fi nalAmd1.pdf.
120 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Cement is used mainly as an ingredient in concrete, a 

ubiquitous building material. Cement acts as an adhesive 

when mixed with other ingredients, including water.

Cement is made in several steps: quarrying and crushing 

the raw materials; grinding the materials to a fi ne powder; 

heating the materials in a kiln to produce “clinker” (the 

intermediate products); and grinding the clinker, together 

with gypsum, to a fi ne powder.

Cement kilns produce over 80 percent of the sulfur dioxide 

(SO2) and nitrogen oxides (NOx) emissions associated 

with cement manufacturing and over 40 percent of the 

particulate (PM) emissions. The kiln is a long, brick-lined 

cylindrical steel shell that is rotated with an electric drive. 

It is set at an angle, such that the material introduced at 

one end moves to the other end by gravity. At the lower 

end, burners, most of which fi re coal, provide the heat that 

turns the raw materials into clinker. 

In 2003, there were 116 portland cement plants in 

37 states and two in Puerto Rico. California, Texas, 

Pennsylvania, Michigan, Missouri and Alabama were 

the six largest producers, with about one-half of the 

country’s total production. After falling during the 1980s, 

cement production in the U.S. has grown over 25 percent 

since 1990. In 2003, cement plants in the U.S. produced 

approximately 87 million tons of portland cement and 4.5 

million tons of masonry cement (which contains portland 

cement) (USGS, 2004).

Sector Profi le

Most commonly, cement refers to a fi ne, powdery 

substance made of heated and pulverized limestone and 

clay that sets into a solid mass when mixed with water. 

This type of cement is also called “hydraulic cement” 

because it requires water to set. Cement is used mainly as 

an ingredient in concrete.

Buildings, dams, roadways and countless other structures 

are either made of, or supported by, concrete. Concrete 

has four ingredients: cement, water, coarse aggregate 

(e.g., rocks) and fi ne aggregate (e.g., sand). Cement 

reacts with the water to form a paste that hardens around 

the aggregates to make concrete. The proportions of 

ingredients vary based on the desired properties of the 

concrete. A typical batch of concrete is about 10–15 

percent cement, 60–70 percent aggregate (coarse and fi ne) 

and 15–20 percent water (Portland Cement Association, 

Chapter 9

Cement Manufacturing 
 Chapter 9 - Cement Manufacturing 121

2005).

The most common type of cement is portland cement, 

so named by Joseph Aspdin, who patented it in 1824, 

because the color of the concrete he made with the cement 

reminded him of limestone quarried on the Isle of Portland 

in the English Channel (Portland Cement Association, 

2005). Portland cement accounts for about 93 percent of 

the cement produced in the U.S. Of the remainder, about 5 

percent is masonry cement and about 2 percent is blended. 

The raw materials for portland cement come from four 

categories of substances: calcium carbonate and oxides 

of silicon, aluminum and iron. Limestone is most often 

used to fulfi ll the calcium carbonate requirement and is 

the predominant raw material in cement. There are more 

than 30 raw materials that can be used to fulfi ll the other 

mineral requirements. The mix of raw materials used 

depends on their availability and on the desired properties 

of the cement (EPA, 2000; Davis, 2000). 

Both masonry cement and blended cements are produced 

in portland cement plants and contain portland cement as 

an ingredient (Davis, 2000). Masonry cement commonly 

contains a fi nely ground mixture of portland cement, 

limestone and air-entraining agents (EPA, 2000). Blended 

cements are produced by blending two or more types 

of fi ne materials, primarily portland cement, ground 

granulated blast furnace slag, fl y ash, silica fume, calcined 

clay, hydrated lime and pre-blended combinations of those 

materials (Portland Cement Association, 2005).

The process of making portland cement involves (EPA, 

2000):

quarrying and crushing raw materials;

proportioning and grinding the raw materials to a 

high degree of fi neness;

pyroprocessing (the heating process that takes place 

in the cement kiln) the crushed raw materials in a 

rotary kiln to produce clinker (intermediate products 

of fused raw materials); and

grinding the clinker to a fi ne powder, along with an 

appropriate proportion of gypsum (calcium sulfate, a 

white or clear sulfate of lime also used in plaster) to 

produce cement.

The American Society for Testing and Materials (ASTM) 

specifi es eight different types of portland cement. The 

types have various physical and chemical attributes and are 

designated by Roman numerals and letters (Types I, IA, II, 

IIA, III, IIIA, IV and V). Type I is considered a general 

purpose cement, suitable for all uses, while the other types 

have specifi c qualities such as rapid setting, high strength 

and resistance to high sulfate soil or groundwater that can 

damage cement (Portland Cement Association, 2005). 

The different types of portland cement are made by using 

appropriate combinations of raw materials, blending the 

intermediate product (clinker) with specifi ed amounts of 

•

•

•

•

Table 9.1

Cement Manufacturing Sector Emissions

Process Type

PM2.5 SO2 NOx

Tons/year

Percent 

of Sector 

Emissions Tons/Year

Percent 

of Sector 

Emissions Tons/Year

Percent 

of Sector 

Emissions

Dry kilns 7,209 31% 64,467 35% 90,000 39%

Wet kilns 1,232 5% 80,288 44% 71,638 31%

Preheater/precalciner kilns 866 4% 15,076 8% 23,904 10%

Preheater kilns 165 1% NA NA 9,003 4%

In-process fuel 647 3% 12,548 7% 14,622 6%

Material handling, storage and 

grinding

5,621 24% NA NA NA NA

Manufacturing (not classifi ed) 2,181 9% NA NA NA NA

Clinker cooler 2,028 9% NA NA NA NA

Other 3,123 14% 11,787 6% 24,522 10%

Total 23,072 100% 184,167 100% 233,689 100%

Source: EPA, 2005, based on facilities listed under SIC code 3241
122 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

gypsum (calcium sulfate) and grinding the fi nal product to 

a specifi c degree of fi neness (EPA, 2000).

There are four types of kilns used at cement and clinker 

facilities: wet kilns, long dry kilns, dry kilns with a 

suspension preheater and dry kilns with a precalciner 

system. Wet kilns are the least energy-effi cient and are 

becoming less common; their use has declined by 77 

percent since 1974. All kilns built since 1975 (56 percent 

of existing U.S. capacity) use the dry process. About 81 

percent of the cement produced in the U.S. is manufactured 

using the dry process (Portland Cement Association, 

2005).

Emissions

Most SO2 and NOx emissions from the cement 

manufacturing process come from the operation of the 

kiln. About 41 percent of fi ne particulate matter (PM2.5) 

emissions come from the kiln.

PM emissions also result from handling, storing and 

grinding both raw materials and the intermediate product 

(clinker). Historically, the cement industry has focused on 

control of PM emissions, both because it is in the fi nancial 

interest of manufacturers to capture and recycle PM back 

into the process and because federal standards limit PM 

emissions. Almost all stages of the manufacturing process 

include particle capture devices, most frequently fabric 

fi lters or electrostatic precipitators (ESPs). Table 9.1 

summarizes PM2.5, SO2 and NOx and emissions from the 

cement manufacturing industry.

Note that all new kilns are preheater/precalciner kilns; as 

their numbers increase, their share of the overall emissions 

attributable to this sector will also increase while the share 

of emissions attributable to dry and wet kilns will decline. 

Cement Manufacturing

Facilities produce portland cement by grinding and then 

heating a mixture of calcium carbonate with oxides of 

silicon, aluminum and iron to a high temperature. The 

raw materials used to create this mixture depend on the 

mineral content of available sources. The materials can 

include clay, shale, sand, slag, fl y ash, or waste rock from a 

limestone quarry for silicon or aluminum; and mill wastes, 

pyrite, or iron ore for iron. Calcium carbonate, usually 

from quarried limestone, is the most important ingredient 

and plants are frequently located near limestone sources 

(EPA, 2000). 

Figure 9.1 shows a basic cement manufacturing process. 

Raw materials are gathered and then crushed in a grinding 

mill, after which they can be stored separately for later 

use or immediately combined in proper proportions in the 

mixer. Raw materials can be introduced in a dry form 

or in a 30–40 percent liquid slurry. The mixture of raw 

materials enters the kiln through the feeder, where the 

heating process begins. A cement kiln is a long rotating 

tube that is heated at one end (EPA, 1994). As the material 

moves through the kiln, it is gradually heated and turned 

into clinker. Clinker pieces are hard, gray spheres 

with diameters of one-eighth to 2 inches, composed of 

compounds resulting from the chemical reactions that take 

place in the kiln (Davis, 2000). 

Fig. 9.1 Basic Cement Manufacturing Process

KILN

Burning Zone

(Clinker Zone)

Calcining Zone Drying Zone

Kiln Burner

Cooler

RAW

MATERIALS

GRINDING

MILL MIXER

FEEDER

GRINIDING STORAGE

MILL

Source: EPA, 1995
 Chapter 9 - Cement Manufacturing 123

After leaving the kiln, the clinker is cooled to lock in its 

mineral properties. Clinker can be stored or immediately 

ground into the fi nal product. During the fi nal grinding, 

approximately 5 percent by weight of gypsum is added to 

the clinker to control the setting time of the cement (Davis, 

2000).

Raw material extraction, handling and grinding; and 

clinker cooling and grinding can result in fugitive PM 

emissions. If a manufacturer uses the raw materials in a 

slurry form (as in the wet process), PM emissions are very 

low for the raw material grinding and handling portions 

of the manufacturing process. Since the fi nal mix (in 

either the wet or dry process) is a fi nely ground powder, it 

is a source of fugitive PM emissions during handling and 

transport. 

The largest source of emissions in cement manufacturing, 

and the centerpiece of the process, is the kiln. As shown 

in Table 9.1, over 40 percent of PM emissions, about 87 

percent of SO2 emissions and about 84 percent of NOx 

emissions are associated with cement manufacturing are 

generated by cement kilns (EPA, 1994). The kiln is a long 

(150–750 feet long, 10–25 feet in diameter) brick-lined 

cylindrical steel shell that is rotated with an electric drive 

at one to three revolutions per minute (EPA, 2000). The 

kiln is set at an angle that allows the material fed in at one 

end to move by gravity to the other end. At the lower end, 

burners provide the heat that turns the raw materials into 

clinker.

The burners used to heat the kiln use coal or other fossil 

fuels (EPA, 1994). In 1998, about 82 percent of cement 

plants were coal-fi red, about 3 percent burned natural 

gas and approximately 1 percent used oil. The remaining 

14 percent of the plants used other combinations of fuel, 

such as waste materials supplemented with coal or another 

fossil fuel (EPA, 2000).

There are four processing stages, regardless of the type 

of kiln that is employed: evaporation, dehydration, 

calcination and reaction. Both the evaporation and 

dehydration stages take place in the drying zone shown in 

Figure 9.1. During evaporation, the material is heated to 

212 degrees Fahrenheit (°F) to remove water. The material 

temperature is then increased during dehydration to 

approximately 800°F. As the material moves through the 

kiln, temperatures increase during the calcination stage to 

1,600°F–1,800°F, and carbon dioxide and calcium oxides 

are formed. The heating of the material to a temperature 

that is high, but below the melting or fusing point, results 

in the loss of moisture and the decomposition of carbonates 

and other compounds. Finally, during the reaction stage 

(in the burning zone in Figure 9.1), the calcium oxides are 

heated to 2,750°F to form clinker (EPA, 2000).

As noted previously, of the four types of cement kilns, 

wet kilns are the least energy-effi cient and their use has 

declined dramatically. Wet kilns and long dry kilns use 

older technologies and have only one fuel combustion 

zone. Newer preheater and precalciner kilns have two 

combustion zones and use dry raw materials; some older 

kilns with preheaters have only one combustion zone. 

Kilns with two combustion zones suppress some thermal 

Table 9.2

Controlled PM Emission Factors for Different Kiln Typesa

Cement Kiln Type Control Device PM Emission Rateb (lb/ton of clinker)

Wet kiln ESP 0.77

Fabric fi lter 0.46

Long dry kiln ESP 1.0

Fabric fi lter 0.20

Preheater kiln ESP 0.26

Fabric fi lter 0.25

Preheater/precalciner kiln ESP 0.048

Fabric fi lter 0.21

a. This table shows controlled as opposed to uncontrolled emissions because PM emissions from kilns are normally controlled. 

Uncontrolled emissions are approximately 130 pounds per ton (lb/ton) of clinker from wet process kilns and 250 lb/ton of clinker from 

preheater kilns.

b. Includes fi lterable PM (collected on or before the fi lter of an EPA Method 5 sampling train); does not include condensable PM (collected 

in the impinger portion of a PM sampling train).

Source: EPA, 1995
124 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

NOx formation.1

The main process difference between a wet kiln and a 

long dry kiln is that a 30–40 percent liquid slurry of raw 

materials is introduced to the feeder in a wet kiln, while 

a dry feed of raw materials is introduced in a long dry 

kiln. Historically, producers using raw materials with 

higher moisture content (15–20 percent) favored the wet 

process (EPA, 2000). However, there have been signifi cant 

effi ciency advancements in the dry process, especially with 

the use of suspension preheater and precalciner systems. 

Accordingly, new kilns always use the dry process.

Suspension preheater systems preheat the dry feed before 

it enters the kiln, using a four-stage system of funnels, 

called cyclones.2

 As the material moves through each of 

the four cyclones it is heated, so that it is already 40–50 

percent calcined by the time it enters the kiln. This process 

1. Four types of NOx form in cement manufacturing: fuel NOx, thermal 

NOx, feed NOx and prompt NOx. Fuel NOx forms from the oxidation of 

nitrogen in the fuel; thermal NOx results from the oxidation of nitrogen 

in the process air at high temperatures; feed NOx comes from the heating of the raw materials; and prompt NOx is generated by the reaction 

of fuel-derived radicals with elemental nitrogen in a hydrocarbon 

fl ame. Of these four, fuel NOx and thermal NOx are the most signifi cant. 

Prompt NOx is particularly insignifi cant to total NOx formation (Greer, 

2003).

2. Preheater cyclones should not to be confused with cyclones that can 

be used for PM removal.

allows the kiln to be shortened and signifi cantly increases 

the effi ciency of the system compared to wet and long dry 

kilns (EPA, 2000).

In a precalciner system, a second burner is used to carry 

out calcination in a separate vessel. The raw material is 

almost 95 percent calcined before entering the kiln. The 

precalciner system is the most energy-effi cient cementmaking process and is used by all newer cement plants in 

the U.S. (EPA, 2000).

Precalciner systems are much larger than the other 

systems. Precalciner systems in the U.S. have an average 

capacity of about 869,000 metric tons per year, compared 

to 307,000 metric tons per year, 265,000 metric tons per 

year, and 406,000 metric tons per year for long wet, long 

dry, and suspension preheater kilns, respectively. This size 

differential has led to a decline in the number of kilns but 

an increase in total U.S. cement-making capacity (EPA, 

2000).

Kiln PM emissions come from the exhaust gases generated 

during the heating process. These emissions consist 

of a mix of particles from the various stages of material 

processing and from the combustion of the heat source. 

Collectively, the particulates are known as cement kiln 

dust (CKD) and are collected with ESPs or fabric fi lter for 

use or disposal. Handling CKD can result in fugitive dust 

Table 9.3

Controlled PM Emissions Factors for Other Processes

Process Control Device

PM Emissions Rate 

(lb/Ton of Clinker)

Clinker cooler ESP 0.096

Fabric fi lter 0.13

Gravel bed fi lter 0.21

Raw mill Fabric fi lter 0.012

Raw mill feed belt Fabric fi lter 0.0031

Raw mill weigh hopper Fabric fi lter 0.019

Raw mill air separator Fabric fi lter 0.032

Finish grinding mill Fabric fi lter 0.0080

Finish grinding mill feed belt Fabric fi lter 0.0024

Finish grinding mill weigh hopper Fabric fi lter 0.0094

Finish grinding mill air separator Fabric fi lter 0.028

Primary limestone crushing Fabric fi lter 0.0010

Primary limestone screening Fabric fi lter 0.00022

Limestone transfer Fabric fi lter 0.000029

Secondary limestone screening Fabric fi lter 0.00031

Source: EPA, 1995
 Chapter 9 - Cement Manufacturing 125

emissions (Davis, 2000). 

Tables 9.2 and 9.3 present the best available information 

on PM emissions from this industry sector. Note that the 

data in both of these tables are from AP-42 and have a 

rating of “D” or “E” on a rating scale in which “A” denotes 

excellent data quality and “E” denotes poor data quality. 

This refl ects the diffi culty of obtaining emissions rates for 

cement kilns. 

SO2 and NOx emissions rates for cement kilns vary widely 

throughout the industry. Continuous monitoring has 

shown that emissions from a single source can vary by an 

order of magnitude over time (Davis, 2000). The amount 

of sulfur in the raw materials and in the fuel determines 

the amount of SO2 emissions, while fuel combustion is a 

major source of NOx emissions (Davis, 2000). Partly as 

a result of these uncertainties, there are as yet no federal 

New Source Performance Standards (NSPS) for SO2 or 

NOx emissions from cement plants. 

Tables 9.4 and 9.5 present the best available information 

on SO2 and NOx emissions from this industry sector. The 

data in Table 9.4 are also from AP-42 and have a rating of 

“C” or “D.” 

Table 9.5 shows uncontrolled NOx emissions as reported 

in EPA’s 1994 “Alternative Control Techniques (ACT) 

Document—NOx Emissions from Cement Manufacturing” 

and similar data from AP-42. The ACT data were 

collected from 51 cement kilns (22 wet kilns, ten long dry 

kilns, ten preheater kilns and nine precalciner kilns). The 

AP-42 data all have ratings of “D.” According to EPA’s 

year 2000 review of NOx control technologies, the ACT 

data provide the best available information on cement 

manufacturing emissions (EPA, 2000).

Emissions Control Opportunities

Most PM2.5, SO2 and NOx emissions from cement 

manufacturing are produced by cement kilns. Additional 

PM2.5 emissions come from the handling, grinding and 

storing of raw materials, clinker and the fi nal product.

Over the last half century, the cement-manufacturing 

industry has moved away from wet kilns in favor of 

more effi cient preheater and precalciner dry kilns. The 

movement towards more effi cient kilns has had the 

indirect benefi t of reducing uncontrolled emissions of 

SO2 and NOx per ton of clinker (refl ected in the average 

emissions rates shown in Tables 9.4 and 9.5). However, the 

change from wet to dry kilns has increased the potential 

for PM emissions, since the raw materials are more likely 

to produce fugitive dust emissions. Industry-wide use of 

fabric fi lters and ESPs has controlled a large percentage of 

these emissions.

Additional process modifi cations to increase energy 

effi ciency, such as instruction and training of kiln 

operators and consistent raw material and coal preparation, 

can reduce PM, SO2 and NOx emissions. However, many 

of these process modifi cations are dependent on sitespecifi c characteristics, making it diffi cult to provide 

general estimates of cost-effectiveness (EPA, 2000).

Controlling PM Emissions

Federal standards limit PM emissions; moreover, it is 

also in the fi nancial interest of manufacturers to capture 

and recycle PM. As a result, almost all stages of the 

manufacturing process include particle capture devices 

Table 9.4

Uncontrolled SO2 Emission 

Factors for Different Kiln Types

Cement Kiln Type

SO2 Emission 

Rate (lb/Ton of 

Clinker)

Wet kiln 8.2

Long dry kiln 10

Preheater kiln 0.55

Preheater/precalciner kiln 1.1

Source: EPA, 1995

Table 9.5

Uncontrolled NOx Emission Factors for Different Kiln Types

Cement Kiln Type

ACT NOx Emission Rate 

(lb/Ton of Clinker)

Range of NOx Emissions 

(lb/Ton of Clinker)

AP-42 NOx Emission Rate 

(lb/Ton of Clinker)

Wet kiln 9.7 3.6-19.5 7.4

Long dry kiln 8.6 6.1-10.5 6.0

Preheater kiln 5.9 2.5-11.7 4.8

Preheater/precalciner kiln 3.3 0.9-7.0 4.2

Source: EPA, 1994, 1995a
126 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

(most frequently, fabric fi lters or ESPs).

PM emissions come from combustion sources in the 

kiln and from material handling, grinding and storage 

operations (with the latter producing fugitive emissions). 

Control devices available for combustion sources are fabric 

fi lters and ESPs. Both fabric fi lters and ESPs are discussed 

in detail in Chapter 5, Boiler Technologies. As they do for 

boilers, the control devices remove PM from an exhaust 

stream. However, given the high pollutant loadings 

associated with cement operations, control devices must be 

relatively large compared to boiler control devices. Both 

fabric fi lters and ESPs have PM collection effi ciencies of 

95–99 percent (LADCO, 2005).

Control devices for sources of fugitive PM emissions are 

also primarily fabric fi lters and ESPs. In order to capture 

fugitive PM emissions, material handling, grinding and 

storage operations must be enclosed and vented to the 

control device (LADCO, 2005). Dust collectors can also 

control non-kiln PM sources. Dust collectors are similar 

to fabric fi lters but have temperature restrictions (a limit 

of 200°F or 400°F, depending on the fi lter media) and are 

effective only on low-fl ow applications. However, dust 

collectors require less room than fabric fi lters or ESPs and 

are therefore useful for areas with space restrictions. Dust 

collectors have a PM control-effi ciency of over 99 percent 

(LADCO, 2005).

If there is adequate space for ductwork and the control 

device is properly sized, multiple PM sources can be 

directed to and controlled by one control device (LADCO, 

2005). If fugitive emissions sources are not enclosed, 

they can be controlled using wind screens, water sprays, 

equipment enclosures and other fugitive dust controls (EC, 

2000).

Where existing control device collection-effi ciencies are 

lower than desired, several performance improvements are 

possible. These include rebuilding ESPs, possibly with a 

larger number of collection areas and increased treatment 

times, and using fabric fi lters in combination with ESPs. 

In the settlement of a recent lawsuit in Wyoming, one 

cement manufacturer agreed to replace an existing ESP 

with a fabric fi lter to reduce PM emissions that were 

causing a kiln to exceed opacity limits (Associated Press, 

2005). 

Controlling SO2 Emissions

The clinker-making process itself provides substantial 

SO2 control and has historically been considered the best 

available technology for controlling cement kiln SO2

emissions (Davis, 2000). A number of Best Available 

Control Technology (BACT) determinations since 2000 

have listed “process” as the technology for controlling SO2

emissions (Sumter Cement Company, 2005). Cement kiln 

systems have highly alkaline internal environments that 

can absorb up to 95 percent of potential SO2 emissions. 

However, variations in the kiln feed can lower the sulfur 

absorption rate to 70 percent (EPA, 1995a). This makes 

raw material selection an important consideration in 

controlling SO2 emissions (Linero, 2001). Where raw 

material sulfur is very low and preheater/precalciner kilns 

are used, almost all SO2 emissions are scrubbed during the 

manufacturing process and emissions are effectively zero 

(Linero, 2005b).

Fabric fi lters on cement kilns are also reported to absorb 

some SO2, although an absorbing reagent—such as calcium 

oxide, an intermediary product of clinker formation—must 

be present in the fi lter cake for SO2 capture to occur (EPA, 

1995b).

As much as 50 percent of the SO2 can be removed from the 

kiln exhaust gases when this gas stream is used in drying 

raw materials. When this approach is used, moisture and 

calcium carbonate are simultaneously present for suffi cient 

time for the chemical reaction with SO2 to occur (EPA, 

1995b).

Cement manufacturing plants also use fl ue gas control 

technologies such as fl ue gas desulfurization (FGD). 

Advanced, wet and dry FGD are all possible SO2 control 

technologies. Advanced FGD is estimated to have a 

control-effi ciency of 95–99.5 percent and, as an added 

benefi t, generates gypsum—a mineral needed in the fi nal 

stages of cement production—as a byproduct. However, 

no cement manufacturing units in the U.S. currently use 

advanced FGD (LADCO, 2005). Descriptions of all three 

types of FGD systems are included in Chapter 5, Boiler 

Technologies. Note that wet and dry FGD systems are 

sometimes referred to as wet and dry scrubbers.

Wet FGD has an SO2 control-effi ciency of 90–99 percent. 

Using wet FGD in the cement industry requires more care 

than using this technology on utility boilers because of 

particulate build-up and clogging. Most of these problems 

can be avoided if the FGD is installed downstream of an 

effi cient fabric fi lter (LADCO, 2005). Five cement plants 

in the U.S. currently operate with wet scrubbers to control 

SO2 emissions (Sumter Cement Company, 2005).

Dry FGD has an SO2 control-effi ciency of 90–95 percent. 

Most dry FGD systems are installed on preheater or 

preheater/precalciner kilns. Dry FGD is not recommended 

for wet kilns because it can cause corrosion problems in 

that setting (LADCO, 2005).

Lime spray injection is an alternative to traditional wet and 

dry scrubbers and has been proposed as a less expensive 

alternative for reducing SO2. In this process, a fi ne mist 

of lime product is sprayed into the exhaust gas before it 

reaches the PM removal equipment. The lime droplets 
 Chapter 9 - Cement Manufacturing 127

Table 9.6

SO2 Control Technology Cost Estimates for Long Dry Kilns

Control 

Technology

Size 

(Tons of Clinker per 

Year)

Capital Costs 

($ Million)

Annual Costs 

($ Million)

Cost Effectiveness 

($ per Ton)

AFGD 300,000 7.3–22.9 3–6 2,000–4,000

600,000 14.1–45.9 6.1–11.9

1,200,000 28.1–91.6 12.1–23.7

Wet FGD 300,000 2.43–36.5 3–9 2,000–6,200

600,000 4.9–73.0 6–18.4

1,200,000 9.5–142.5 11.9–36.8

Dry FGD 300,000 1.45–37.0 3–9 1,900–7,000

600,000 2.9–84.9 5.5–20.0

1,200,000 5.6–165.5 10.7–38.9

Source: Lake Michigan Air Directors Consortium, 2005

Table 9.7

SO2 Control Technology Cost Estimates for Preheater Kilns

Control 

Technology

Size 

(Tons Clinker per Year)

Capital Costs 

($ Million)

Annual Costs 

($ Million)

Cost Effectiveness 

($ per Ton)

AFGD 300,000 4.5–14.5 1.1–3.0 13,600–38,600

600,000 8.9–29.0 2.3–5.9

1,200,000 17.8–58.0 4.5–11.8

Wet FGD 300,000 1.5–23.1 0.9–4.8 9,700–64,600

600,000 3.1–46.3 1.6–9.5

1,200,000 6.2–92.5 3.2–18.9

Dry FGD 300,000 0.9–26.3 0.9–5.4 10,000–72,800

600,000 1.8–52.6 1.7–10.6

1,200,000 3.6–105.2 3.3–21.0

Source: Lake Michigan Air Directors Consortium, 2005

react with the SO2 and are captured by the fabric fi lter or 

ESP (Linero, 2001).

The Lake Michigan Air Directors Consortium (LADCO) 

conducted an economic analysis of Best Available Retrofi t 

Technologies (BART) for controlling emissions of SO2

(and other pollutants) from long dry kilns and preheater 

kilns using model facilities. Tables 9.6 and 9.7 present 

results from the LADCO analysis.

Note that the cost estimates in Tables 9.6 and 9.7 are based 

on modeling commissioned by LADCO in support of its 

“Cement Best Available Retrofi t Technology (BART) 

Engineering Analysis.”3 The LADCO analyses included a 

detailed review of available technologies and control costs. 

As a result of the modeling assumptions and the inclusion 

of a wide spectrum of operating conditions, some of the 

cost ranges are extremely large. LADCO emphasizes that 

site-specifi c analyses are required to assess facility-level 

costs accurately.

Controlling NOx Emissions

There are three categories of NOx emissions controls for 

cement manufacturing facilities: process modifi cations, 

combustion controls and post-combustion controls. 

It is important to note that preheater and precalciner kilns 

3. The LADCO website includes detailed information on the modeling. Supporting documentation is available at: www.ladco.org/Regional_Air_Quality.html.
128 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

have lower NOx emissions rates than wet and long dry 

kilns, because preheater and precalciner kilns have two 

combustion zones. With two combustion zones, the fuel 

combustion temperatures for the preheating or precalcining 

step can be lower than the combustion temperatures for the 

kiln fi ring; at lower temperatures, less NOx is formed.

Because of the different fi ring confi gurations, not all 

controls are applicable to all kiln types. While the process 

modifi cations discussed below can be used on any of the 

four kiln types, mid-kiln fi ring is effective only on wet or 

long dry kilns. Low-NOx burners (LNBs) are effective 

only on indirect-fi red kilns.

Process Modifi cations. Many process modifi cations 

focus on improving energy effi ciency, thereby resulting 

in a reduction of all emissions. Two process controls 

that specifi cally target NOx emissions are continuous 

emissions monitoring systems (CEMS) and a patented feed 

modifi cation technique known as the CemStar Process 

(EPA, 2000).

CEMS allow operators to continuously monitor oxygen and 

carbon monoxide (CO) emissions in cement kiln exhaust 

gases. The levels of these gases indicate the amount of 

excess air in the combustion zone. At a given excess air 

level, NOx emissions increase as the temperature increases. 

Knowing the excess air level allows operators to maintain 

a lower temperature and thereby minimize NOx creation. 

Additionally, some studies indicate that reducing excess 

air by half can reduce NOx emissions by about 15 percent 

(EPA, 2000).

The CemStar Process, developed and patented by TXI 

Industries, is a raw feed modifi cation process that can 

reduce NOx emissions by about 30 percent and increase 

production by approximately 15 percent. It involves the 

addition of a small amount of steel slag to the raw kiln 

feed. Steel slag has a chemical composition similar to 

clinker and many of the chemical reactions required to 

convert steel slag to clinker take place in the steel furnace. 

By substituting steel slag for a portion of the raw materials, 

facilities can increase thermal effi ciency and thereby 

reduce NOx emissions. In 2000, 11 facilities in the U.S. 

were using or planning to incorporate CemStar (EPA, 

2000).

Combustion Controls. Combustion modifi cations 

to reduce NOx emissions from cement kilns fall into two 

categories: staged combustion of air and staged combustion 

of fuel. The primary staged air combustion controls are 

LNBs. LNBs reduce the formation of NOx by staging the 

combustion process, producing fuel-rich and fuel-lean 

zones within the combustion fl ame (EPA, 1999). LNBs are 

commonly used on electric generating unit and industrial 

boilers and are described in more detail in Chapter 5, 

Boiler Technologies.

LNBs have been used on cement kilns for over 20 years. 

However, they are effective only on indirect-fi red kilns, 

which account for a small share of the existing U.S. kiln 

population. The Portland Cement Association reported 

to EPA in 2000 that a survey of 81 percent of the kilns 

in the U.S. indicated that 14 percent of these kilns use 

some type of LNB (EPA, 2000). New kilns are designed 

to incorporate indirect fi ring and LNBs to reduce 

NOx emissions. LNBs with indirect fi ring have been 

determined to be BACT for several new facilities since 

2000 (Sumter Cement Company, 2005).

As compared to direct-fi red systems, indirect-fi red systems 

use less air to convey fuel to the combustion zone; they 

therefore add less air to the combustion zone. This reduces 

the oxygen available for NOx formation. Conversion of a 

direct-fi red kiln to an indirect-fi red kiln involves adding 

particle separation equipment, such as a cyclone or a 

baghouse and a fan, to provide the air used to transport 

the powdered coal from storage to the kiln. In addition to 

reducing NOx formation, indirect fi ring increases overall 

energy effi ciency by allowing a greater proportion of hot 

clinker-cooler air to be used as secondary combustion air 

(EPA, 2000).

LNBs can be paired with fl ue gas recirculation (FGR) for 

additional NOx reductions of 15–38 percent (EPA, 2000). 

FGR is a temperature reduction process that involves 

recirculating a portion of the fl ue gas with the combustion 

air. Recirculation lowers the combustion temperature, 

reducing NOx formation (EPA, 1999). FGR is not effective 

on all kilns because of the high temperatures required to 

create clinker. If use of FGR lowers the temperature too 

much, the process can be compromised (EPA, 2000).

All new cement kilns are of the preheater or precalciner 

variety. These take advantage of staged fuel combustion 

by having two fi ring zones. One zone is located before the 

place where the material enters the kiln; the other zone is 

at the end of the kiln. These kilns are more fuel effi cient 

and have lower NOx formation than wet or long dry kilns. 

Multi-staged combustion can be used with preheater/

precalciner kilns to reduce NOx formation. Multi-staged 

combustion reduces NOx through the use of staged air or 

staged fuel combustion at the burning locations (Sumter 

Cement Company, 2005).

Wet and long dry kilns can also make use of staged fuel 

combustion by injecting solid fuel into the calcining zone 

of the kiln. This technique is called mid-kiln fi ring. Midkiln fi ring requires solid and slow burning fuels—most 

systems use whole tires, although at least one uses baled 

industrial waste. The fuel is dropped into the calcining 

zone, where it burns at the calcining temperature (between 

1,600°F and 1,800°F) instead of at the clinker-forming 

temperature (2,750°F). The lower combustion temperature 

reduces NOx formation. The average NOx reduction using 
 Chapter 9 - Cement Manufacturing 129

this method is 41 percent for wet kilns and 33 percent for 

long dry kilns (EPA, 2000).

Tire-derived fuel can also be used in precalciners in 

place of all or some portion of the fossil fuel used for 

combustion. In one case, NOx emissions reductions of 

about 30 percent occurred when tire-derived fuel was 

substituted for 47 percent of the coal (EPA, 2000).

Post-combustion Controls. The potential fl ue gas 

treatments for reducing NOx emissions are selective 

catalytic reduction (SCR) and SNCR. Both of these 

technologies are commonly used on electric generating 

and industrial boilers and are described in more detail 

in Chapter 5, Boiler Technologies. SCR reduces NOx

emissions by chemical reduction, using a reducing agent 

(ammonia) and a catalyst. SCR is currently in operation 

on a cement kiln in Germany (Solnhofer Portland Cement 

Plant) and has been used on pilot cement plants in other 

parts of Europe. It is not, however, currently used on kilns 

in the U.S. (Sumter Cement Company, 2005). 

Data from the SCR pilot projects in Europe suggest 

reduction effi ciencies of 85–95 percent. One study from 

the Netherlands reported a cost-effectiveness of €2,500 per 

metric ton of NOx (about $2,700 per ton) in late October 

2005 (EC, 2000). The BART analysis conducted by 

LADCO estimated an SCR removal effi ciency of 70–90 

percent, and cost-effectiveness of $600–$1,900 per ton of 

NOx removed on long dry kilns, and $500–$1,200 per ton 

of NOx removed on preheater kilns (LADCO, 2005).

Table 9.8

NOx Control Technology Performance

Technology

Average 

Emissions 

Reduction (%)

Range of 

Emissions 

Reductions (%)

Average Annual CostEffectiveness ($ per 

Ton NOx Reduced)a

Range of Annual CostEffectiveness 

($ per Ton NOx Reduced)a

CemStar 33 25–40 550 ND

Indirect fi ring with a 

low-NOx burnerb

27 4–47 440 300–620

Long dry kiln with 

low-NOx burnerc

40 ND ND 166–1,299

Preheater kiln with 

low-NOx burnerc

40 ND ND 175–1,201

Mid-kiln fi ring 

(wet kilns only)

41 28–59 55 (460)–730

Mid-kiln fi ring 

(dry kilns only)

33 11–55

SNCRd 40 10–50 1,750 1,000–2,500

SNCRe ND 31–83 ND 605–700

SCRf 90 85–95 2,700 ND

SCRe ND 31–83 ND 530–1,135

Long dry kiln with 

SCRc

ND 70–90 ND 586–1,902

Preheater kiln with 

SCRc

ND 70–90 ND 504–1,232

ND = No Data

a. In 1997$, except where noted.

b. Converting a direct-fi red kiln to an indirect-fi red kiln and retrofi tting with an LNB roughly doubles the cost effectiveness.

c. From LADCO, 2005. Cost-effectiveness in 2004$.

d. These estimates are based on the use of an SNCR technology called NOx-OUT® at three facilities.

e. From Haug, 2002. Emissions reductions range includes all data from the study. Cost-effectiveness in 2002$. Junker, 2000 supports 

SNCR emissions reductions of 80-85%.

f. From European Commission, 2000; based on one demonstration project in the Netherlands. Cost effectiveness in 2000$.

Source: EPA, 2000; European Commission, 2000; Huag, 2002; LADCO, 2005
130 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

A review conducted by the Solnhofer Portland Cement 

Company with the German Federal Environmental Offi ce 

(the organization that funded the project) and Lurgi 

(designers of the SCR equipment used in the project) 

compared the costs of SCR and SNCR on a preheater kiln 

(Haug, 2002). According to the results of that study, the 

costs of an SNCR system that reduces NOx emissions 

from 5.4 pounds per ton (lb/ton) of clinker to 3.6 lb/ton 

of clinker is €560 per ton of NOx ($605 per ton of NOx). 

The same review estimated the cost to reduce NOx with an 

SNCR to 2.3 lb/ton of clinker and 0.9 lb/ton of clinker to 

be approximately €590–€650 per ton of NOx ($640–$700 

per ton of NOx), respectively. By contrast, the review 

found that the cost of control by SCR per ton of pollutant 

decreased as the reductions increased, from approximately 

€1,050–€490 per ton of NOx ($1,135–$530 per ton of 

NOx) for reductions to 3.6 lb/ton and 0.9 lb/ton of clinker, 

respectively. The costs of control with an SNCR and SCR 

are equal when facilities reduce emissions to 2.3 lb/ton of 

clinker (about a 56% reduction in NOx).

SNCR also relies on the reduction of NOx by exposure to a 

reducing agent (such as ammonia), but it does not involve 

the use of a catalyst. The catalyst in an SCR increases the 

reaction rate; without the catalyst, temperature becomes 

very important. The temperature range needed for 

SNCR occurs in the middle of wet and long dry kilns. It 

is diffi cult to inject the reducing agents in the middle of 

the kiln at a continuous rate, which makes it diffi cult to 

use SNCR on wet and long dry kilns. On preheater and 

precalciner kilns, the temperatures at the cooler end of the 

kiln and in the preheating area are appropriate for SNCR 

use (EPA, 2000).

As of 2000, at least 18 kilns in Europe had installed 

SNCR (EC, 2000). By 2004, there were approximately 32 

SNCR installations in Germany alone (Verein Deutcher 

Zementwerke, 2004). Currently, only one full-size kiln in 

the U.S. has installed SNCR. Average control-effi ciencies 

for these installations are 50–60 percent (Linero, 2005a). 

The Florida Department of Environmental Protection 

(DEP) has recently approved at least three cement permit 

applications that include SNCR with LNBs and multi-stage 

combustion as BACT (Florida DEP, 2005). 

Table 9.8 summarizes the potential NOx reductions and 

cost-effectiveness associated with control technologies 

discussed in this section.

Regulatory Authority

As we have indicated in Chapter 4, which discusses the 

Clean Air Act in more detail, the states and the federal 

government share responsibility for regulating criteria 

pollutants (e.g., PM, SO2, NOx) from stationary sources 

like those operating at portland cement plants. The federal 

government has more of the burden of regulating toxic 

air pollutants, but—for both criteria pollutants and air 

toxics—states and local areas are free under federal law 

to adopt more stringent standards than the Clean Air Act 

requires. 

This section describes federal standards that apply under 

the Clean Air Act to pollutant emissions from portland 

cement plants. 

Reasonably Available Control Technology

State Implementation Plans (SIPs) for areas that are in 

nonattainment of federal ambient air quality standards 

must include Reasonably Available Control Technology 

(RACT) requirements for new and existing sources. RACT 

standards are non-binding federal guidelines; for Volatile 

Organic Compounds (VOCs), the guidelines are known 

as Control Technique Guidelines (CTGs). Guidelines 

known as Alternative Control Techniques (ACTs) outline 

the control technologies that are available to address NOx

emissions from specifi c source sectors, but do not specify 

actual RACT limits. There are no sector-specifi c ACTs or 

CTGs for SO2, PM10 or PM2.5.

ACT guidelines applicable to NOx emissions from cement 

manufacturing can be found at www.epa.gov/ttn/catc/

products.html#aptecrpts. SIP writers should bear in mind 

that although the ACTs may provide a starting point, 

they are unlikely to represent the actual RACT limits 

that states will choose to adopt. That is the case because 

RACT standards are intended to refl ect advancements in 

technology, and most of the ACTs are outdated—some, 

seriously so. Additionally, the ACTs are guidelines only, 

not actual federal limits. Even if they were federal limits, 

many states would have the leeway to enact more stringent 

standards. And since the ACTs do not set limits, even state 

prohibitions against enacting more stringent standards may 

be inapplicable.

New Source Performance Standards

The NSPS typically apply, in both attainment and 

nonattainment areas, to new, modifi ed and reconstructed 

sources within specifi c source categories. 

Under the Clean Air Act, 40 CFR §§ 60.60, et seq. (subpart 

F), NSPS requirements apply to portland cement plants that 

commenced construction, modifi cation or reconstruction 

after August 17, 1971. The following sources at portland 

cement plants are covered: kilns, clinker coolers, raw 

mill systems, fi nish mill systems, raw mill dryers, raw 

material storage, clinker storage, fi nished product storage, 

conveyor transfer points, and bagging and bulk loading 

and unloading systems.

The NSPS for portland cement plants appear in Table 9.9.
 Chapter 9 - Cement Manufacturing 131

Regional Haze/Best Available Retrofi t 

Technology

Under the regional haze program, BART requirements 

for the control of PM2.5 and PM2.5-precursor emissions 

apply to certain large sources (in both attainment and 

nonattainment areas) that began operation between 1962 

and 1997. The 26 source categories subject to BART 

requirements include portland cement plants. However, 

states have not yet developed BART rules under the 

regional haze program.

New Source Review/Prevention of 

Signifi cant Deterioration

New Source Review (NSR) requirements apply to new 

and modifi ed large stationary sources in nonattainment 

areas, while Prevention of Signifi cant Deterioration 

(PSD) requirements apply to large stationary sources 

in attainment areas. Under these programs, plants in 

nonattainment areas are required to implement Lowest 

Achievable Emission Rate (LAER) controls and plants 

in attainment areas are required to implement BACT. 

Neither BACT nor LAER standards are codifi ed because 

they are intended to refl ect technology advancements as 

they occur.

There have been a number of BACT determinations 

for cement kilns since 2000. Many of the BACT 

determinations for NOx have included LNBs and multistage combustion. Recent permit applications in Florida 

have included SNCR in addition to LNBs and multi-staged 

combustion. The BACT determinations that include all 

three technologies include proposed NOx limits as low 

as 1.95 lb/ton of clinker (30-day average). Recent BACT 

determinations that include LNBs and multi-staged 

combustion but no SNCR have NOx limits ranging from 

2.8 to 5.52 lb/ton of clinker (Florida DEP, 2005; Sumter 

Cement Company, 2005).

BACT determinations for SO2 from preheater/precalciner 

kilns since 2000 have limits (and some pending proposed 

limits) that range from 0.20 to 2.16 lb/ton of clinker. Some 

of the limits are based on very low sulfur in the raw 

materials and SO2 removed during the process; other limits 

are based on wet scrubbing and dry scrubbing (Florida 

DEP, 2005; Sumter Cement Company, 2005). 

Recent BACT determinations for PM and PM10 are as low 

as 0.1 lb/ton of process feed. This limit is for the combined 

kiln and clinker cooler emissions and is about a quarter 

of the federal Maximum Achievable Control Technology 

(MACT) and NSPS limits discussed below (Florida DEP, 

2005).

The Florida Department of Environmental Protection 

maintains a list of NSR and PSD cement plant construction 

permits for plants in Florida on their website. The have 

additional technical information on BACT for cement 

plants. The information can be found at www.dep.state.

fl .us/Air/permitting/construction.htm.

Maximum Achievable Control Technology

MACT standards address emissions of Hazardous 

Air Pollutants (HAPs) from new and existing sources 

in identifi ed industry categories. They apply in both 

attainment and nonattainment areas to sources with 

potential emissions of 10 tons per year of a single HAP or 

25 tons per year of combined HAPs.

Under the Clean Air Act, 40 CFR §§63.1340, et seq.

(subpart LLL), PM emissions from portland cement 

manufacturing plants are regulated as a surrogate for 

HAPs.4

The MACT standards for portland cement plants appear in 

Table 9.10.

4. The MACT standards include limits for dioxins and furans and total 

hydrocarbon, which are not included in this discussion.

Table 9.9

NSPS for Portland Cement Plants (40 CFR §§60.60, et seq. (subpart F))

Source Particulate Matter Limit Opacity Limit

Kiln (wet or dry) 0.15 kg/metric ton of feed (dry basis) 

(0.30 lb/ton)

20%

Clinker cooler 0.050 kg/metric ton of feed (dry basis) to the kiln

(0.10 lb/ton)

10%

Any covered plant source 

besides the kiln or the clinker 

coolera

10%

a. Raw mill systems, fi nish mill systems, raw mill dryers, raw material storage, clinker storage, fi nished product storage, conveyor transfer 

points, and bagging and bulk loading and unloading systems.
132 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

On October 12, 2005, EPA published fi nal MACT 

standards (at 40 CFR §§63.1200, et seq. (subpart EEE)) for 

hazardous waste combustors, which include facilities that 

combust hazardous waste in cement kilns.5

 The standards, 

which may be the subject of ligitation, cover portland 

cement plants that use hazardous waste as a fuel source 

and regulate PM emissions as a surrogate for HAPs.6 A 

summary of the standards is included in Table 9.11.

Clean Air Interstate Rule

In March 2005, EPA promulgated the Clean Air Interstate 

Rule (CAIR), which aims to address pollution transport 

5. A facility continues to be regulated as an affected source until it 

ceases burning hazardous waste and initiates closure requirements pursuant to the Resource Conservation and Recovery Act (RCRA).

6. The MACT standards establish limits for pollutants—including dioxins and furans, mercury, semivolatile metals, low volatile metals, total 

chlorine, carbon monoxide and hydrocarbons—that are not included in 

this discussion.

that contributes to the non-attainment of eight-hour 

ozone and PM2.5 air quality standards throughout the 

eastern U.S. CAIR identifi es 28 states and the District 

of Columbia as contributing to unhealthy levels of ozone 

and/or fi ne particles in downwind nonattainment areas and 

requires these states to implement additional NOx and SO2

emissions reductions. CAIR requires states that contribute 

to downwind PM2.5 nonattainment to achieve annual NOx

and SO2 emissions reductions; states that contribute to 

downwind ozone nonattainment are required to achieve 

further seasonal NOx emissions reductions. States can 

choose how to achieve these reductions, but it is expected 

that most, if not all states, will opt to cap emissions of 

electric generating units (EGUs) according to budgets 

established by EPA and to participate in EPA- administered 

emissions trading programs. None of the sources operating 

at portland cement plants can be included in any of the 

federal CAIR trading programs without disqualifying the 

state from participation in the federal trading regimes.

EPA promulgated the predecessor to CAIR in 1998. 

Table 9.11

MACT Standards for Cement Kilns Using 

Hazardous Waste as a Fuel Source (40 CFR 

§§63.1200, et seq. (subpart EEE))

Source

PM Emission 

Limit

Opacity 

Limita

Existing Kilns 0.028 gr/dscfb 20%

New or 

reconstructed kilns

0.0023 gr/dscf 20%

a. The opacity standards do not apply to sources equipped 

with a bag leak detection system under 63.1206(c)(8) or a 

particulate matter detection system under 63.1206(c)(9).

b. gr/dscf, grains per dry standard cubic feet corrected to 7% 

oxygen. 1 grain = 0.002 ounces.

Table 9.12

Expected Emission Limits for Alternative 

Control Techniques in Federal Implementation 

Plan

Kiln Type

Emission Limit 

(lb/ton, 30-day 

average)

Long wet kiln 6.0

Long dry kiln 5.1

Preheater kiln 3.8

Precalciner or preheater/precalciner 2.8

Source: EPA, 1998

Table 9.10

MACT Standards for the Portland Cement Manufacturing Industry (40 CFR §§63.1340, et seq. (subpart 

LLL))

Source PM Emissions Limit Opacity Limit

All kilns and in-line kiln/raw millsa 0.15 kg/Mgb

 (0.30 lb/ton) of feed (dry 

basis)

20%

All clinker coolers 0.050 kg/Mg (0.10 lb/ton) of feed 

(dry basis)

10%

Raw mills and fi nish mills NA 10%

All raw material dryers and material handling points NA 10%

a. In-line kiln/raw mill refers to a part of the portland cement production process in which a dry kiln system is integrated with the raw 

mill so that all or a portion of the kiln exhaust gases are used to perform the drying operation of the raw mill without use of an auxiliary 

heat source. In this system, the kiln is capable of operating without the raw mill, but the raw mill cannot operate without the kiln gases; 

consequently the raw mill does not generate a separate exhaust gas stream.

b. Mg = megagrams, 1 Mg = 1 metric ton.
 Chapter 9 - Cement Manufacturing 133

Known as the NOx SIP Call, it requires 22 states in the 

eastern U.S. to implement NOx reductions. Under the 

rule, affected states were required to amend their SIPs and 

limit NOx emissions to meet EPA-specifi ed ozone season 

NOx emissions budgets. Although the NOx SIP Call did 

not mandate the source categories that were required to 

reduce emissions, EPA proposed a Federal Implementation 

Plan (FIP) as part of the process that surrounded the 

implementation of the SIP call and the resolution of related 

litigation. EPA’s calculation in the proposed FIP included 

NOx emissions reductions of 30 percent from uncontrolled 

levels for large cement manufacturing sources. The rules 

outlined in the FIP apply to kilns with process rates of at 

least:

10 tons per hour for long wet kilns;

12 tons per hour for long dry kilns;

16 tons per hour for preheater kilns; and

22 tons per hour for precalciner and preheater/

precalciner kilns.

EPA proposed a technology standard to implement 

required NOx reductions. The technology standard would 

have required kiln owners to install and operate LNBs, 

mid-kiln fi ring or alternative control techniques (subject 

to EPA approval) that achieve at least the emissions limits 

shown in Table 9.12.

State and Local Policy Measures

As discussed in the Introduction to this report, states and 

localities are free under federal law to adopt more stringent 

standards than the Clean Air Act requires, although in 

some instances state laws limit this authority. SIP writers 

are presumably familiar with any such constraints under 

applicable local laws and regulations. The Introduction 

also outlines possible approaches for imposing more 

stringent state and local standards.

A review of BACT determinations indicates that there are 

numerous opportunities for reducing emissions from the 

cement manufacturing process. For NOx control, recent 

BACT determinations in Florida require the installation of 

SNCR controls with LNBs and multi-staged combustion. 

These determinations include NOx limits as low as 1.95 

lb/ton of clinker (30-day average). Although there is only 

one SNCR device currently installed at a cement plant 

in the U.S., there are over 32 SNCR systems installed on 

kilns in Germany and many more in the rest of Europe. 

Recent BACT determinations that do not include SNCR 

but do include LNBs and multi-staged combustion have 

NOx limits ranging from 2.8 to 5.52 lb/ton of clinker. 

Recent BACT determinations have set SO2 limits ranging 

from 0.20 to 2.16 lb/ton of clinker for preheater/precalciner 

•

•

•

•

kilns, compared to uncontrolled emissions from preheater/

precalciner kilns that can be as high as 7.6 lb/ton of clinker 

(and up to 10 lb/ton of clinker for existing long dry kilns). 

Where the process itself does not achieve satisfactory 

SO2 emissions levels, wet FGD technology can provide 

an SO2 control effi ciency of 90–99 percent. Of more 

than 100 cement plants in the country, only fi ve currently 

use wet scrubbers to control SO2, suggesting substantial 

opportunities for the industry to improve its emissions 

profi le. Dry FGD technology (not recommended for 

wet kilns) and lime spray injection are other SO2 control 

options, although they are less effective.

Apart from imposing stringent permit limits on individual 

plants, state and local areas should consider the following 

opportunities for the adoption of regulations to address 

PM emissions from the cement manufacturing sector.

The fi rst option is for states and localities to adopt more 

stringent PM standards. The MACT PM limits for 

cement kilns that burn hazardous waste (Table 9.11) are 

more stringent than the MACT PM standards for cement 

kilns that burn fossil fuels (Table 9.10). State and local 

regulators can consider requiring kilns that do not burn 

hazardous waste to meet the more stringent standards, 

absent a showing that particular plants cannot achieve 

these levels.

A second option is for states and localities to adopt rules 

promulgated by the South Coast Air Quality Management 

District (AQMD) to control fugitive dust. The South 

Coast AQMD Board recently adopted a new rule to reduce 

PM emissions from cement processing equipment, storage 

piles and facility roadways (South Coast AQMD, 2005). 

According to the South Coast AQMD staff report, the rule 

is designed to achieve PM reductions of 2 tons per day 

in the South Coast basin and has a cost-effectiveness of 

$1,000–$4,000 per ton of PM reduced (Pham, 2005).

The proposed rule includes opacity limits of 10 percent 

from any operation at the facility except for open piles, 

roadways and unpaved areas, where a higher opacity 

limit of 20 percent applies. Additionally, the operator of 

a facility cannot cause or allow the facility to emit any 

dust plume that is visible more than 100 feet away in 

any direction. The rule includes additional requirement 

for enclosing conveying systems and material loading, 

unloading and storage areas. Operators must use dust 

suppressants as necessary. They must also enclose 

crushing, screening, milling, grinding, blending, drying, 

heating, mixing, sacking, palletizing, packaging and other 

related operations. The enclosed areas must be vented to a 

control system. Additionally, all kilns and clinker coolers 

must be vented to control systems (South Coast AQMD, 

2005). 

Finally, under the South Coast AQMD rule, all control 
134 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

systems must have outlet concentrations that do not exceed 

0.01 grains of PM per dry standard cubic foot for equipment 

installed before November 4, 2005, and concentrations that 

do not exceed 0.005 grains of PM per dry standard cubic 

foot for equipment installed after November 4, 2005. The 

rule includes the performance requirements for existing 

baghouses as specifi ed in the U.S. Industrial Ventilation 

Handbook (South Coast AQMD, 2005).

References

Associated Press. “Cement Plant, Enviros Settle Suit,” 

Billings Gazette, October 28, 2005.

Davis, W., Air & Waste Management Association. Air 

Pollution Engineering Manual: Second Edition, 2000.

European Commission (EC), Institute for Prospective 

Technological Studies. Integrated Pollution Prevention and 

Control (IPPC): Reference Document on Best Available 

Techniques in the Cement and Lime Manufacturing 

Industries, March 2000. www.epa.ie/Licensing/

IPPCLicensing/BREFDocuments/FileUpload,448,en.pdf.

Florida Department of Environmental Protection 

(DEP). New Source Review/Prevention of Signifi cant 

Deterioration, accessed December 11, 2005, from: www.

dep.state.fl .us/air/permitting/construction.htm.

Greer, W., Portland Cement Association. Interactions 

Among Gaseous Pollutants from Cement Manufacture 

and Their Control Technologies, 2003. www.cement.org/

pdf_fi les/SN2728.pdf.

Haug, N., G. Sauter, G. Samant. “Einsatz der High-DustSCR Technologie in der Zementindustrie (Application of 

High-Dust SCR Technology in the Cement Industry),” 

obtained from Linero, A.A., Florida Department of 

Environmental Protection, December 11, 2005.

Junker, P., Country Administration of Gotland, Sweden, 

Environmental Department. Reduction of Nitrogen Oxides 

with SNCR Technology at Slite Cement Plant, November 

2000.

Lake Michigan Air Directors Consortium (LADCO). 

Midwest Regional Planning Organization (RPO) Cement 

Best Available Retrofi t Technology (BART) Engineering 

Analysis, prepared by MACTEC Federal Programs/

MACTEC Engineering and Consulting, Inc., March 30, 

2005. www.ladco.org/reports/rpo/Regional Air Quality/

Cement_BART_Engineering Analysis + Appendix 

A1.pdf.

Linero, A.A., Florida Department of Environmental 

Protection. “What’s Up with Cement Plant Permitting?” 

(Paper # 884), Air and Waste Management Association 

94th Annual Conference & Exhibition, June 2001. www.

dep.state.fl.us/air/permitting/construction/cement/

CementPaper.zip.

Linero, A.A, Florida Department of Environmental 

Protection. “SNCR NOx at U.S. Cement Plants. Is SCR 

Close Behind?” (Paper # 638), Air and Waste Management 

Association 98th Annual Conference & Exhibition, June 

2005. (2005a)

Linero, A.A., Florida Department of Environmental 

Protection. Personal communication with M.J. Bradley & 

Associates, December 2005. (2005b)

New York State Department of Environmental 

Conservation (NYDEC). “Portland Cement Plants,” 

NYDEC Rules and Regulations Part 220, September 22, 

1994. www.dec.state.ny.us/website/regs/part220.html.

Pham, M. Further Reduction of Particulate Emissions 

from Cement Manufacturing Facilities (Draft Staff 

Report for Proposed Rule 1156, South Coast Air Quality 

Management District), October 4, 2005. www.aqmd.gov/

rules/proposed/r1156/Oct4SR1156.pdf.

Portland Cement Association, “Cement & Concrete 

Basics,” accessed October 15, 2005, from: www.cement.

org/basics/index.asp.

South Coast Air Quality Management District (AQMD). 

Proposed Rule 1156: Further Reductions of Particulate 

Emissions from Cement Manufacturing Facilities,

October 4, 2005. www.aqmd.gov/rules/proposed/r1156/

Oct4PR1156.pdf.

Sumter Cement Company. Application to Construct New 

Portland Cement Plant, NSR/PSD Construction Permit 

for Center Hill Plant, submitted to Florida Department 

of Environmental Protection, September 8, 2005. www.

dep.state.f l.us/Air/permitting/construction/sumter/

APPLICATION.zip.

U.S. Department of the Interior, U.S. Geological Survey 

(USGS). Mineral Commodity Summaries 2004, 2004. 

http://minerals.er.usgs.gov/minerals/pubs/mcs/2004/

mcs2004.pdf.

U.S. Environmental Protection Agency (EPA). Alternative 

Control Techniques Document—NOx Emissions from 

Cement Manufacturing, March 1994. http://epa.gov/ttn/

catc/dir1/cement.pdf.

U.S. Environmental Protection Agency (EPA). “Chapter 

11: Mineral Products Industry: Portland Cement 

Manufacturing,” AP 42, Fifth Edition, Volume I, January 
 Chapter 9 - Cement Manufacturing 135

1995. www.epa.gov/ttn/chief/ap42/ch11/fi nal/c11s06.pdf. 

(1995a)

U.S. Environmental Protection Agency (EPA), EPA Offi ce 

of Compliance Sector Notebook Project: Profi le of the 

Stone, Clay, Glass, and Concrete Products Industry, 

September 1995. www.epa.gov/compliance/resources/

publications/assistance/sectors/notebooks/stclglsn.pdf. 

(1995b)

U.S. Environmental Protection Agency (EPA). “Federal 

Implementation Plans To Reduce the Regional Transport 

of Ozone; Proposed Rule,” Federal Register 63(203): 

56393, October 21, 1998. www.epa.gov/fedrgstr/EPAAIR/1998/October/Day-21/a26431.htm.

U.S. Environmental Protection Agency (EPA). Technical 

Bulletin: Nitrogen Oxides, Why and How They Are 

Controlled (EPA 456/F-99-006R), November 1999. www.

epa.gov/ttn/catc/dir1/fnoxdoc.pdf.

U.S. Environmental Protection Agency (EPA). NOx

Control Technologies for the Cement Industry, September 

2000. www.epa.gov/ttn/naaqs/ozone/ozonetech/cement_

NOx_update_09152000.pdf.

U.S. Environmental Protection Agency (EPA). 1999 

National Emissions Inventory Final Version 3.0, obtained 

from EPA staff, October 2005. www.epa.gov/ttn/chief/net/

1999inventory. html.

Verein Deutcher Zementwerke, Forschungsinstitut 

der Zementindustrie. Umweltdaten der Deutschen 

Zementindustrie 2004 (Environmental Data of the German 

Cement Industry 2004), September 2005. www.vdzonline.de/fileadmin/gruppen/vdz/3LiteraturRecherche/

UmweltundRessourcen/Umweltdaten/VDZ_

Umweltdaten_2004.pdf.
136 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

The U.S. steel industry, which produced about 106 

million tons of raw steel in 2004, is comprised of two 

primary segments: 17 integrated iron and steel plants 

and approximately 93 “minimills” that melt steel scrap 

in electric arc furnaces (EAFs). The integrated plants 

currently account for about 47 percent of U.S. steel 

production, while the minimills account for the remaining 

53 percent (USGS, 2005). Integrated plants use iron ore 

in blast furnaces to produce molten iron; the molten iron 

and ferrous scrap are then loaded (the terminology in the 

industry is “charged”) into basic oxygen furnaces (BOF), 

where oxygen is blown into the vessel to remove carbon 

and produce steel. The EAFs at minimills produce steel by 

melting mostly recycled ferrous scrap. Steel is currently 

used principally in the automotive and construction 

industries. 

The iron and steel industry grew rapidly with the advent 

of the railroad in the latter half of the nineteenth century 

and remained a driving force in the American economy 

through the fi rst half of the twentieth century, when the 

U.S. was the world’s largest steel producer. Since the end 

of World War II, however, the U.S. has lost a large share 

of the world market for steel—particularly since 1969, 

when U.S. steel production peaked at 141 million tons. In 

the ensuing years, new, more effi cient steel plants have 

been built overseas, aided by reductions in shipping costs 

(Gordon, 1991). In addition, other materials, such as 

plastic, have substituted for steel in various applications. 

Meanwhile—partly due to the energy crises of the 1970s 

and the declining cost of scrap metal—smaller minimills 

have claimed a growing share of steel manufacturing 

capacity by converting scrap metal to steel, rather than 

engaging in the traditional steel production process 

performed by integrated steel mills. 

Most integrated steel mills in the U.S. are located in the 

Great Lakes region near the automotive industry. While 

minimills operate throughout the country, the majority 

are located in the traditional steel making states of 

Pennsylvania, Ohio and Indiana. 

The production of steel at integrated steel mills involves 

numerous processes, all of which have their own extensive 

set of operations (see Figure 10.1). Each of these many 

processes is a potential source of emissions; as a result, 

controlling emissions from iron and steel plants is a 

complicated matter.

This chapter focuses only on coke production and primary 

iron and steel production, not on the host of related 

industries (e.g., ferroalloy plants, ferrous foundries) that 

either produce inputs for steel plants or cast the fi nished 

steel into more refi ned products. Although these facilities 

also produce fi ne particulate matter (PM2.5), sulfur 

dioxide (SO2) and nitrogen oxide (NOx) emissions (albeit 

in lesser quantities than primary steel production), they 

are beyond the scope of this report. Moreover, even for 

Chapter 10

Iron and Steel
 Chapter 10 - Iron and Steel 137

coke and primary iron and steel production, the approach 

taken in this chapter is somewhat different than that 

taken for other industry sectors discussed in this report. 

One of the reasons for this is the very large number of 

emissions points in the coke, iron and steel production 

process. Additionally, perhaps partly because many of 

these emissions are fugitive in nature, information on the 

emissions reductions that can be achieved through various 

approaches and on the cost-effectiveness of controls is 

scant (EPA, 2002b). Although we are unable to present 

complete information on all emissions control options and 

their cost-effectiveness, we attempt to provide a robust 

presentation on the range of available control opportunities 

for the most signifi cant sources of emissions associated 

with the iron and steel industry’s primary production 

processes. 

Sector Profi le

Since the 1970s, American steel production has ranged 

between 80 and 110 million tons per year, with the U.S. 

ceding the spot as the world’s top steel producer to China 

during that time (DOE, 2001). The past few years have 

seen a continuation of the downward trend in U.S. 

production, as large quantities of relatively low-cost steel 

from overseas have further eroded the American steel 

base. Since 1998, over 30 steel companies have declared 

bankruptcy (EPA, 2004a; USGS, 2005). Nonetheless, 

the American iron and steel industry is still a formidable 

economic force: in 2004, 95 facilities produced $51 billion 

of product (EPA, 2004a). 

Steel is manufactured in two different types of facilities: 

integrated mills and minimills. Each accounts for about 

half of total steel production and each has a very different 

emissions profi le. The two types of facilities use different 

input materials, but the output from both is molten steel, 

which is then formed into a variety of products. Integrated 

mills are typically used for high tonnage production of 

carbon steels, while minimills produce carbon steels and 

specialty steels (EPA, 1995).

An integrated steel mill includes a blast furnace for making 

iron and a BOF for making steel. A few integrated mills 

also have coke plants and sinter plants; the latter convert 

fi ne-sized raw materials into an agglomerated product 

(sinter) of suitable size for charging into a blast furnace. 

All have continuous casters for casting the molten steel and 

almost all have rolling mills onsite or nearby to make the 

fi nal steel shapes. The basic raw material inputs include 

coke, iron ore pellets (taconite), sinter and fl ux materials 

for removing impurities from molten metal.

Coke is produced by heating coal in the absence of 

oxygen at high temperatures in coke ovens. Next comes 

the production of molten iron, which involves heating the 

Fuel

Coal

Iron ore pellets

BOF slag

Flux

Sinter

Exhaust gas

Hot metal

(iron)

Ferrous

scrap

Heated

BF gas blast air

Clean

BF gas

Air

Oxygen

Molten

steel

Cast steel

Steel shapes

Rolling

mills

Continuous

caster

Basic

oxygen

furnace

Blast

furnace Coke oven

battery

Byproduct

recovery

plant

ESP or

venturi

scrubber

Venturi Stoves

scrubber

Coke

Raw coke

oven gas

Byproducts (tar, light

oil, ammonium sulfate)

Clean coke

oven gas

Fig. 10.1 Processes at an Integrated Steel Mill 

Source: EPA, 2005k
138 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

coke, iron ore and limestone in a blast furnace. Then, 

molten iron from the blast furnace is combined with fl ux 

and scrap steel in the BOF and high-purity oxygen is 

injected to remove carbon and produce steel. Forming and 

fi nishing operations follow (EPA, 1995). 

There are 17 integrated steel mills in the U.S., with a total 

of 34 blast furnaces, 44 BOFs and fi ve sinter plants. Most 

of these integrated mills are concentrated in the Great 

Lakes region, particularly Indiana, Michigan and Ohio 

(EPA, 2001a, updated November 2005). 

Minimills produce steel from metal scrap using EAF 

technology. Minimills use primarily scrap steel as the 

input material; the scrap steel is melted and refi ned by 

passing an electric current through it. Minimills do not 

involve the coke making and iron making steps that take 

place at integrated mills due to the nature of their raw 

materials (EPA, 1995). There are 93 minimills operating 

throughout the country.

Emissions

Table 10.1 summarizes emissions from the iron and steel 

industry. EPA provides highly detailed data on emissions 

from this sector, but these data do not reveal how emissions 

break down by major categories, i.e., coke making, iron 

making, steel making in BOFs, and steel making in EAFs.

Integrated Steel Mills

As noted above, integrated steel mills use a three-step 

process to produce steel: 

coke making, from coal in a coke oven; 

iron making, using coke in a blast furnace to produce 

molten iron; and

steel production, from molten iron and ferrous scrap 

in a BOF.

Coke making

Most coke is produced in by-product recovery ovens by 

heating pulverized bituminous coal in an oxygen-free 

atmosphere until all volatile components evaporate. It is 

•

•

•

used as a fuel and as a reducing agent to melt and reduce 

iron ore. 

Coal, which is fi rst pulverized to prepare for coking, is 

fed into the coke oven (in a process known as “charging”) 

through ports in the top of the oven. The ports are then 

sealed, and the coal is heated at high temperatures for 

14 to 36 hours. Coke manufacturing is done in batches, 

with each coke battery comprising a series of ten to 100 

individual ovens, side by side. The walls separating 

adjacent ovens, as well as the end walls, contain a series of 

vertical heating fl ues. Volatile compounds are driven from 

the coal and the solid carbon remaining in the oven is the 

coke (EPA, 1995, 2000a).

The volatile matter driven from the coal moves upward 

through cast iron “goosenecks” into a common horizontal 

pipe called the collecting main, which connects all the 

coke ovens in series. The collecting main directs the gases 

evolved during coking to an adjacent byproduct recovery 

plant, where combustible gases and other coal byproducts 

are recovered. The cleaned gas is used to underfi re the 

coke ovens and for fuel elsewhere in the plant. Coke oven 

gas is the most common fuel for underfi ring coke ovens 

(EPA, 2000a). 

When the coking is complete, doors on both sides of 

the oven are removed and the coke is pushed out into a 

rail “quench” car. The quench car moves to a quench 

tower, where the hot coke is sprayed with water to cool 

it and prevent it from continuing to burn. The car then 

discharges the coke onto a wharf to drain and cool further, 

after which grates on the wharf are opened and the coke 

falls onto a conveyor that carries it to the crushing and 

screening station. After it is broken into appropriate sizes, 

the coke goes to the blast furnace or to storage (EPA, 1995, 

2000a).

PM is emitted at a number of different points in the coke 

making process, including during oven charging, from 

leaking doors, when pushing coke into the quench car, 

and during coke quenching (EPA, 2000a). EPA’s initial 

Maximum Achievable Control Technology (MACT) rule 

for coke ovens targeted leaks from doors and lids, as well 

as offtake system emissions. For purposes of EPA’s more 

recent MACT rule dealing with integrated iron and steel 

plants, the emissions sources of concern for coke making 

are the pushing of coke from the ovens, the quenching of 

incandescent coke, and the battery stacks (the discharge 

point for the underfi ring system). Coke pushing results 

in fugitive particulate emissions that may include volatile 

organic compounds (VOCs), while quenching results in 

PM emissions with traces of organic compounds (EPA, 

2002b).

Coke can also be made at a non-recovery coke oven. In 

this type of oven, the gas produced by the coking process 

Table 10.1

Iron and Steel Sector Emissions (1999)

Process Type

PM2.5

(tons)

SO2

(tons)

NOx

(tons)

Iron and steel 

primary production

44,922 89,305 97,977

Source: EPA, 2005a
 Chapter 10 - Iron and Steel 139

is immediately combusted in and around the coke oven 

to provide heat for the coking process, thus eliminating 

the need for a by-product plant and producing far fewer 

emissions than a by-product coke oven.

Table 10.2 includes PM emissions factors from the 

predominant sources of coke oven emissions.

Iron making

The blast furnace, a tall steel vessel lined with heatresistant brick, converts iron ore into a more pure and 

uniform iron. Conveyor systems of carts and ladles carry 

inputs and outputs to and from the blast furnace (EPA, 

2002b).

Iron ore is the primary source of iron for integrated iron 

and steel mills, although iron can also be captured by 

“sintering”—a process of agglomeration whereby fi ne 

grains, pollution control dust, sludge, and other materials 

are mixed, ignited, and fused into cakes for charging to 

the blast furnace. Together with the iron materials, coke 

(for fuel) and limestone (the fl ux) are charged into the top 

of the furnace; meanwhile, hot air is forced in from the 

bottom. These react to form molten reduced iron, carbon 

monoxide and slag. Some of the carbon also remains in 

the iron, which allows iron and steel to harden when they 

are cooled rapidly. Molten iron and slag collect in the 

hearth at the base of the furnace (EPA, 1995, 2002). 

A hole, called a taphole, is drilled at the base of the hearth 

and the molten iron and slag are periodically removed, or 

cast, from the furnace. Molten iron fl ows into runners that 

lead to transport ladles, while slag fl ows through separate 

runners to a slag pit. The blast furnace byproduct gas is 

cleaned of particulates and used as fuel within the steel 

plant (EPA, 1986, 2001a).

The primary source of blast furnace emissions is the 

casting operation, which generates PM emissions when 

the molten iron and slag come into contact with the air. 

Drilling and plugging the taphole also contribute to casting 

emissions (EPA, 1986).

Steel making in a BOF

BOFs are the standard steel-making furnaces used at 

integrated mills for the fi nal refi nement of iron into steel, 

although two facilities (as of 2002) use EAFs, which we 

discuss in the section on minimills (EPA, 2002b). Molten 

iron from the blast furnace, fl ux, alloy materials and scrap 

are placed in the BOF, where they are melted and refi ned 

by the injection of high purity oxygen. Impurities are 

removed by the combination of the fl uxes and oxygen, 

which results in the production of slag. In addition to slag, 

waste products from this process include carbon monoxide 

and oxides of iron emitted as dust. The furnace is tilted 

in order to remove both steel and slag. In BOFs, unlike in 

EAFs, about 67 percent of the iron is molten iron and only 

about 27 percent is scrap (EPA, 2001c, 2002). 

The operations in the BOF process are:

charging—the addition of molten iron and metal 

scrap to the furnace;

oxygen blow—introducing oxygen into the furnace 

to refi ne the iron;

turndown—tilting the vessel to obtain a sample and 

check temperature;

reblow—introducing additional oxygen if necessary;

tapping—pouring the molten steel into a ladle; and

deslagging—pouring residual slag into a slag pot.

Of these, the oxygen blow portion of the furnace cycle 

accounts for the largest share of emissions, followed by 

tapping and then charging (EPA, 2001b, 2001c).

Sinter Plants

There are currently fi ve sinter plants in the U.S., with 

a combined capacity of 14.6 million tons per year. Like 

many components of the steel industry, the population of 

sinter plants has been declining: as recently as 2001, the 

•

•

•

•

•

•

Table 10.2

Filterablea Particulate Matter Emissions 

Factors from Coke Ovens (lb per ton of 

charged coal) 

Source PM2.5 Total PM

Coke pushing

Uncontrolled 0.19 1.15

Controlled with venturi 

scrubber

0.13 0.18

Combustion Stack 0.44 0.47

Quenching

Uncontrolled (dirty water) 1.01 5.24

Uncontrolled (clean water) 0.13 1.13

With baffl es (dirty water) 0.27 1.30

With baffl es (clean water) 0.03 0.54

Oven charging 0.006 0.016

Mobile scrubber car 0.022 0.072

a. Emissions factors are for fi lterable PM only—not 

condensable PM.

Source: EPA, 2000a
140 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

industry counted seven operational plants (Branscome, 

2005a).

The sintering process converts fi ne-sized raw materials, 

including iron ore, coke breeze, limestone, mill scale, 

and fl ue dust, into an agglomerated product (sinter) of 

suitable size for charging into the blast furnace. The raw 

materials are mixed with water to form a cohesive matrix 

and then placed on a continuous traveling grate called the 

sinter strand. A burner hood at the beginning of the sinter 

strand ignites the coke in the mixture, after which the 

combustion is self-supporting and provides suffi cient heat 

(2,400–2,700 degrees Fahrenheit) to cause surface melting 

and agglomeration of the mix. On the underside of the 

sinter strand is a series of windboxes that draw combusted 

air down through the material bed into a common duct 

leading to a gas cleaning device (either a venturi scrubber 

or a baghouse) (EPA, 1986).

The fused sinter is discharged at the end of the sinter 

strand, where it is crushed and screened. Undersize sinter 

is recycled to the mixing mill and back to the strand. The 

remaining sinter product is cooled in open air or in a 

circular cooler with mechanical fans. The cooled sinter 

is crushed and screened a fi nal time, and then the fi ne 

material is recycled and the product is sent to be charged 

to the blast furnace. Generally, 2.5 tons of raw materials, 

including water and fuel, are required to produce one ton 

of product sinter (EPA, 1986).

Sinter plants generate emissions (in order from largest 

to smallest in quantity) from the windbox exhaust, the 

discharge end (and its associated sinter crushers and 

hot screens), raw material handling, and the cooler. PM 

emissions from the windbox come mainly in the form of 

iron oxides, sulfur oxides, carbonaceous compounds and 

chlorides (EPA, 1986).

Several factors can affect PM emissions. For example, PM 

emissions from the windbox are (not surprisingly) affected 

by the amount of fi ne material being used (e.g., pollution 

control dust from the steelmaking process) and its particle 

size distribution; an increase in fi ne material can result 

in more PM emissions as well as smaller particle sizes in 

the emissions. Operating parameters, such as the bed air 

fl ow rate, bed depth, proper proportioning and mixing of 

the feed materials, and condition of the grate and machine 

seals also affect particulate generation in the windboxes 

(EPA, 2001a).

Minimills

Minimills do not involve the coke-making and ironmaking steps in the steel making process due to the nature 

of their feed stock; instead they use an EAF to melt and 

refi ne scrap metal as the primary raw material. Table 10.3 

shows emissions factors for minimills.

Most of the iron introduced into an EAF—about 88 

percent—is scrap. In most EAFs, electric arcs are formed 

between three carbon electrodes. (A few newer furnaces 

use direct current and only one electrode.) The EAFs 

require a power source to supply the charge necessary 

to generate the electric arc and typically use electricity 

purchased from an outside source. Flux is blown or 

deposited on top of the metal after it has melted; air in 

the furnace and injected oxygen oxidize the impurities. 

Slag containing some of the oxidation products forms on 

top of the molten metal. When the process is complete, 

the furnace is tilted so that the molten steel can be drained 

through one tap and the slag removed from a separate tap. 

In addition to slag, the EAF process produces metal dusts 

and gaseous products (EPA, 1995, 2002). 

Emissions Control Opportunities

As indicated, the steel-making process involves multiple 

steps, each of which comprises many emissions points. 

This section attempts to identify the most signifi cant 

sources of emissions at each step of the process, together 

with control opportunities.

Certain work practices can also be instituted to reduce 

emissions. For example, fugitive emissions from storage 

piles, raw material transfer, roads, etc., can be controlled 

by enclosures, suppression techniques, and road sweeping. 

Every plant should implement a control plan for fugitive 

dust. Raw material transfer points that are particularly 

dusty can be equipped with hoods vented to a baghouse. 

In addition, it is important to monitor capture and control 

equipment to ensure that it is working properly at all 

times.

Coke making

There are a number of different emissions points and steps 

in the coke-making process, including oven charging, 

leaking doors, coke pushing (into the quench car) and 

coke quenching (EPA, 2000a). Burning of uncleaned 

coke oven gas is also a signifi cant source of emissions. 

The basic types of control opportunities for these sources 

of emissions include improved work practices, pollution 

control technology, limited use or even elimination of coke 

in the production of steel, and relatively new processes for 

the production of coke. The best way to reduce emissions 

is to reduce the amount of coke produced and consumed. 

Improved Work Practices and Pollution Control 

Technology. During the coking cycle, emissions can 

occur through poorly sealed doors, charge lids, offtake 

caps, the collecting main and cracks in oven brickwork. 

These emissions can be controlled to some degree by a 

diligent maintenance program, including door cleaning and 
 Chapter 10 - Iron and Steel 141

rebuilding, and by the application of lute (seal) material. 

In addition, operating the coke oven so as to avoid large 

temperature fl uctuations can reduce damage to the battery, 

which causes emissions.

Almost all plants have capture and control systems for 

coke pushing emissions. Additional pollution control can 

be obtained by limiting the frequency of “green pushes,” 

which occur from incomplete coking and overwhelm the 

PM capture system. Regularly observing opacity during 

the pushing process and investigating ovens that produce a 

green push will enhance emissions control (EPA, 2001b).

Coke oven emissions also occur from battery stacks when 

raw coke oven gas leaks through the oven walls, enters 

the fl ues of the underfi ring system and is discharged 

through the stack. These emissions can be limited with 

appropriate diagnostic procedures and work practices. 

Good, systematic operation and maintenance of the battery 

is necessary to prevent green pushes and associated 

stack emissions (EPA, 2002a). Another way to reduce 

emissions during quenching is to substitute an inert gas, 

such as nitrogen, for water when cooling the coke. When 

water is sprayed on the coke, it breaks up the coke and 

generates PM emissions. Substituting an inert gas avoids 

this problem (Davis, 2000). Some plants in Europe have 

switched from water quenching to dry quenching to limit 

emissions of PM and VOCs. This does require major 

construction activities and associated costs (EPA, 2002a). 

The European Commission (EC) estimates that a dry 

quenching plant may cost between 10 and 15 times more 

than a wet quenching station (EC, 2001).

Emissions of PM from coke oven charging can be 

controlled to a large degree by staged charging. Staged 

charging involves dropping coal into an oven at a 

controlled rate; this allows the induced vacuum on the 

oven to handle all the emissions and not be overwhelmed. 

Charging emissions can also be controlled to some degree 

by preventing obstructions through regular cleaning of 

Table 10.3

Emissions Factors for Minimills (units in lb/ton of steel produced unless otherwise specifi ed)

Source Controls NOx SO2 Total PM

Electric arc furnace: charging, 

melting, slagging, tapping (with 

direct shell evacuation and 

roof canopy hood exhausted to 

baghouse)

Without oxygen lancing and oxyfuel burners0.33 0.17 0.064

With oxygen lancing and oxy-fuel 

burners

0.31 0.10

Ladle metallurgy Controlled by baghouse 0.011 0.035 0.0054

Argon oxygen decarburization 

vessel

Controlled by baghouse 0.1

Electric arc furnace and argon 

decarburization vessel

Fugitive emissions, controlled 

by roof monitor exhausted to 

baghouse

0.002

Electric arc furnace and ladle 

metallurgy: charging, melting, 

slagging, tapping, etc. (with direct 

shell evacuation and roof canopy 

hood)

Without oxygen lancing and oxyfuel burners0.39 0.54a

 1.1a

With oxygen lancing 0.48 0.22a

With oxy-fuel burners 0.41 0.096a

With oxygen lancing and oxy-fuel 

burners

0.40 0.58a

Electric arc furnace, ladle 

metallurgy, and continuous caster: 

charging, melting, slagging, 

tapping, etc. (with direct shell 

evacuation and roof canopy hood 

exhausted to baghouse) 

With argon oxygen decarburization 

vessel

0.38 0.046

With oxy-fuel burners and oxygen 

lancing

0.13 0.14

Direct reduced iron reformer Controlled by cyclone and 

scrubber

0.96 0.048

a. Exhausted to baghouse.

b. Pounds per million British thermal units (lb/MMBtu) of heat input.

Source: EPA, 2004c
142 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

the goosenecks and collecting main passages (Davis, 

2000; EPA, 2000a). Leaks from coke oven doors can be 

controlled by cleaning, patching and regular maintenance 

(Davis, 2000; EPA, 2000a). Emissions from coke pushing 

are generally controlled using mobile scrubber cars with 

hoods, a closed shed with vents to evacuate the gas to a 

cleaning device, or traveling hoods with a duct leading 

to a gas cleaner (EPA, 2000a). It is especially important 

to desulfurize coke oven gas before it is burned to reduce 

SO2 emissions. Only 11 of the 16 operating byproduct 

recovery coke plants currently desulfurize this coke oven 

gas (Burns, 1998, updated). 

Emissions from quenching the red-hot coke with 

water after pushing are controlled by a combination of 

techniques: all quench towers should have baffl es that are 

periodically inspected and cleaned and total dissolved 

solids in the water used for quenching should be monitored 

and limited. Dirty river water should not be used (EPA, 

2001b).

Limited Use of Coke and Use of Cokeless 

Technologies. One approach to limiting the emissions 

associated with coke making is to substitute pulverized 

coal for as much as 40 percent of the coke in the blast 

furnace. Other fossil fuels such as natural gas, oil, or tar/

pitch may also substitute for coke to varying and limited 

degrees, but pulverized coal is the most commonly used. 

Pulverized coal is also cheaper than coke; however, the 

coal may degrade the fi nal steel product, so operations 

producing high quality steel generally avoid substitution 

(North Carolina DENR, 1998). One company in Japan has 

even been substituting waste plastic for coke for almost a 

decade (Iino, 2003).

A number of other technologies exist to produce molten 

iron and steel without the use of coke. When coke batteries 

need replacement, they are often replaced by a cokeless 

Direct Reduced Iron (DRI) process. The MIDREX®

and HYL processes are the most common form of DRI 

and account for approximately 85 percent of worldwide 

production at DRI plants, which have a combined global 

capacity of 50 million metric tons (55 million short tons) 

(Environment Canada, 2002). The DRI can substitute for 

scrap steel in an EAF and, to a lesser extent, for scrap in 

a BOF. Using the DRI produces lower emissions while 

at the same time allowing the EAF to produce a higher 

quality steel with fewer byproducts. The capital cost of 

a MIDREX® facility with a capacity of 1.5 million short 

tons per year is approximately $300 million (Environment 

Canada, 2002).

Another way to avoid using coke is to engage in direct 

smelting. One direct smelting method is the Corex 

process, which uses untreated raw coal in place of coke. 

The fi rst Corex demonstration plant was developed in 

1988. While this 300,000 ton-per-year plant has had a 

number of technical diffi culties, Corex plants built more 

recently (including ones in South Korea and India) have 

reportedly been much more successful. In June 2005, 

China announced plans to construct the world’s largest 

Corex plant—designed to produce 1.5 million tons per 

year of molten iron (Kuck, 1998; Siemens, 2005). The 

developer of the technology, Deutsche Voest-Alpine 

Industrieanlagenbau, claims that compared to traditional 

steel making, the Corex process reduces PM emissions 

by over 99 percent, SO2 emissions by 92 percent, and NOx

emissions by 98 percent (STAPPA and ALAPCO, 1999).

The HIsmelt (high intensity smelt) process, developed 

by an Australian company, is another type of cokeless 

iron melting process that converts fi ne ores into molten 

iron. The process has been tested since 1991 in Australia, 

the United Kingdom and the U.S. The fi rst commercial 

size plant began construction in Germany in 2003 and is 

expected to begin producing 800,000 metric tons (970,000 

short tons) of pig iron per year by mid-2006. Other ironmaking facilities may follow (Aker Kvaerner, 2005).

New Coke Production Processes. Employing a 

non-recovery coke battery is another method for reducing 

coke emissions. Unlike traditional coke plants, nonrecovery coke batteries consume the byproducts of coke 

production that are typically recovered and burn them 

directly to produce heat. Because the ovens are under 

negative pressure, there are no leaks of raw coke oven 

gas. The process was developed by the Jewell Coal and 

Coke company, which has operated a plant in Virginia 

since 1989. In 1998, the Indiana Harbour Coke Company, 

a subsidiary of Sunoco, built a 1.3 million-ton-capacity 

non-recovery coke plant in Chicago, Illinois. It uses the 

fl ue gas to produce steam and electricity in a cogeneration 

plant. Capital costs for the plant were $300–$350 million 

(Boselovic, 1998; Environment Canada, 2002). In 

addition, EPA estimates the annual costs for non-recovery 

batteries at approximately $28,300 per battery, due to 

monitoring, recordkeeping and reporting requirements 

needed to assure continuous compliance with standards 

for emissions of hazardous air pollutants (HAPs) (EPA, 

2004b).

Other technologies are under development. For example, 

over the past few years, Japan has been testing a “nextgeneration” coke oven as part of the SCOPE 21 project 

(Super Coke Oven for Productivity and Environment 

Enhancement in the Twenty-First Century). The project 

reduces coking time (and emissions) by preheating the 

coal; it also reduces gas leakage by covering the coke oven 

entirely with steel plates to create an airtight cover. In 

addition, SCOPE 21 is attempting airtight transportation 

of hot coke (Itagaki, 1997; Fukada, 2005).

With funding from DOE, the Calderon Energy Company 

of Ohio has been testing a closed system for coke making 
 Chapter 10 - Iron and Steel 143

while also attempting to identify ways to clean the raw 

gases before they are released. The product gases are 

broken down (cracked) and desulfurized (using limestone) 

to produce hydrogen, carbon dioxide and elemental 

sulfur. According to DOE, if the process is successful 

it will produce no gas emissions, water discharges or 

solid wastes (DOE, 2005). A similar project, conducted 

between 1995 and 1997, cost $7.4 million, 41 percent of 

which was paid by DOE and the rest by Calderon. This 

pilot project produced a yield of approximately 200 tons of 

coke per day. A commercial-scale facility would produce 

approximately 1,600 tons of coke per day (Ailor, 2003). 

Summary of World Bank and European 

Commission Recommendations. The World Bank 

and the EC have published extensive reports within the 

past few years outlining opportunities for pollution control 

from coke making and other industry sectors. For air 

emissions from coke plants, the EC report considers the 

prevention of fugitive smoke and the treatment of coke 

oven gas to be the most important issues. The Commission 

identifi es Best Available Techniques (BAT), which—as 

explained in its report—are not emissions limits but rather 

levels that new installations could meet or exceed and that 

many existing installations could also meet or exceed over 

time (World Bank, 1998b; EC, 2001).

The measures recommended in the World Bank and EC 

approach with respect to coke making (some of which 

overlap with the approaches outlined above) are briefl y 

summarized here:

General

Use cokeless iron- and steel-making processes to 

eliminate the need to manufacture coke.

Use and preheat high-grade coal to reduce coking 

time, increase throughput, and reduce fuel 

consumption. Benefi ciation (crushing and separating 

ore into more desirable substances) and blending 

processes can be used to improve the quality of coal 

feed.

Maintain a free fl ow of gas without obstruction in the 

coke ovens.

Use enclosed conveyors and sieves for coal and coke 

handling to reduce dust formation.

Use sprinklers to suppress dust formation.

Store materials in bunkers or warehouses and provide 

windbreaks where feasible.

Employ a systematic program carried out by specially 

trained maintenance personnel to extensively 

maintain and clean various types of equipment, 

including oven chambers, oven doors and frame 

•

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•

•

•

seals, ascension pipes (the exhaust pipes used during 

coking), charging holes, lids, and other equipment.

Charging

Remove dust particles by evacuation through various 

pipe systems, followed by fabric fi ltration. PM 

emissions rates less than 5 grams (0.011 lb) per metric 

ton of coke are achievable.

Coking

Use large ovens to increase batch size and reduce the 

number of chargings and pushings, thereby reducing 

associated emissions.

Operate coke ovens in a manner that avoids large 

temperature fl uctuations (which cause signifi cant 

emissions).

Install spring-loaded, fl exible-sealing doors or knifeedged doors.

Regularly clean doors, door frames, and hole lids.

Seal lids using a slurry.

Use low leakage door construction.

Firing

Use desulfurized coke oven gas.

Incorporate low-NOx techniques, such as staged 

combustion, in the construction of new batteries.

Pushing

Maintain a suffi cient coking time, thus avoiding 

green pushes. 

Use sheds and enclosed cars or traveling hoods. The 

gases released should be removed and passed through 

fabric fi lters. These techniques can achieve a stack 

emissions rate of less than 5 grams (0.011 lb) of PM 

per metric ton of coke.

Quenching

Use dry instead of wet quenching where feasible and 

fi lter all gases extracted from the dry quenching unit.

If wet quenching is used, provide interceptors 

(baffl es) to remove coarse dust. 

Coke Oven Gas Desulfurization

Achieve desulfurization by using absorption systems 

or oxidative desulfurization, provided that polluting 

water with toxic compounds can be avoided.

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144 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

about 90 percent of remaining PM. The secondary cleaner 

is a high-energy wet scrubber (usually a venturi), which 

removes up to 90 percent of the PM that eludes the primary 

cleaner. Together, these control devices provide a clean 

fuel with less than 0.02 grains of PM per dry standard 

cubic foot (gr/dscf) (EPA, 2001c).

Emissions from the blast furnace top are usually controlled 

effectively with wet-collection systems such as dust 

catchers, venturi scrubbers and precipitators (Davis, 2000). 

Other control techniques include changing operational 

practices, such as increasing the amount of oxygen injected 

in the blast air and raising the blast air temperature 

(Environment Canada, 2002).

EPA’s “Economic Analysis of the Final Integrated Iron 

and Steel NESHAP” provides cost estimates for new 

capture and control systems for casthouses, based on 

responses to an EPA cost survey of plants that had most 

recently installed such systems and on experience with 

a system installed at USS/Kobe Steel (later owned by 

Republic Technologies International). According to EPA, 

the capture and control system was designed for 300,000 

actual cubic feet per minute (acfm) and an air-to-cloth ratio 

of 6.3 feet per minute. The total capital cost (increased 

by 50 percent to refl ect the higher cost of retrofi tting) is 

shown in Table 10.4 as approximately $5 million. The 

annual operating cost was estimated at $730,000 per year, 

resulting in a total annualized cost of $1.2 million per year.

Summary of World Bank and European 

Commission Recommendations. As indicated, the 

World Bank and the EC have published reports outlining 

opportunities for pollution control from multiple industry 

sectors. They include BAT, for blast furnace emissions, a 

summary of which we include below (World Bank, 1998a; 

EC, 2001). Again, some of the techniques listed may 

overlap with approaches already discussed.

Use the direct steel manufacturing process where 

technically and economically feasible.

Replace a portion of the coke used in the blast furnace 

by injecting pulverized coal or by using natural gas 

or oil. The feasibility of pulverized coal injection at 

180 kilograms (397 lb) per metric ton of molten iron 

has already been demonstrated, but higher injection 

rates could be possible.

Recover blast furnace gas to use as an energy source. 

While this gas contains only 10 percent of the energy 

content of natural gas, the fact that vast quantities of 

it are generated means the energy recovery potential 

is very high.

Treat blast furnace gas to remove PM and other 

pollutants. Dry separation techniques (e.g., reusable 

defl ectors) can remove coarse PM, while a scrubber 

or wet electrostatic precipitator (ESP) can then 

remove PM2.5.

•

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•

Gas-tight Operation of Gas Treatment Plant

Minimize the number of fl anges by welding piping 

connections wherever possible.

Use gas-tight pumps (e.g., magnetic pumps).

Avoid emissions from pressure valves in storage 

tanks by connecting the valve outlet to the coke oven 

gas collecting system.

Iron Making

Fugitive PM from the casting operation in the blast 

furnace is the main source of blast furnace emissions. 

Casting is the process whereby molten iron and slag are 

periodically removed (cast) from the furnace through the 

taphole. PM emissions are generated when the molten iron 

and slag contact air above their surface. Resulting PM 

emissions usually comprise iron oxides, magnesium oxide 

and carbonaceous compounds. Drilling and plugging 

the taphole also generate casting emissions (EPA, 1986, 

2001a). 

About half of U.S. blast furnaces control casthouse 

emissions with covered runners and by evacuating 

emissions through capture hoods ducted to a baghouse. 

This suggests that a signifi cant opportunity exists to reduce 

emissions from the roughly half of U.S. blast furnaces that 

have not yet employed these types of control measures 

(EPA, 2001a). Some furnaces also rely on suppression 

techniques, such as using steam or inert gas to reduce the 

formation of pollutants by preventing ambient air from 

contacting molten surfaces (EPA, 1986, 2001a). 

Flue gas from the blast furnace is used to preheat the blast 

air and as fuel for other plant operations. Before blast 

furnace fl ue gas can be burned effi ciently, PM must be 

removed. The gases pass fi rst through a settling chamber 

or dry cyclone to remove about 60 percent of the PM. They 

then undergo a one or two stage cleaning operation. The 

primary cleaner is normally a wet scrubber, which removes 

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Table 10.4

Installed Capital Cost for a Capture and 

Control System for Casthouse Fugitive 

Emissions (2001$)

Item Cost

Baghouse, capture hoods, ductwork $1,920,000

Auxiliary equipment (fans, dampers, 

stacks, etc.)

$577,000

Other (electrical, piping) $840,000

Site-specifi c retrofi t costs (50 percent) $1,670,000

Total installed capital cost $5,007,000

Source: EPA, 2002
 Chapter 10 - Iron and Steel 145

Use pelletized instead of sintered feed where 

appropriate.

During tapping, cover iron runners and use nitrogen 

blankets to reduce dust emissions.

Reduce dust by using enclosed conveyor belts and 

wind barriers.

Recycle collected dust to a sintering plant where 

possible.

Improve blast furnace charge distribution.

In high top pressure blast furnaces, use an expansion 

turbine to recover energy from the large volumes of 

pressurized gas.

Reduce energy use in the hot stoves by using a 

computer to aid hot stove operation, by preheating 

the fuel, and by installing insulation.

Use low-NOx burners to reduce NOx emissions from 

burning fuel in ancillary operations.

Use tar-free runner linings.

Steel Making in a BOF

As indicated above, the most signifi cant sources of 

emissions in the BOF process are charging, tapping, and 

the oxygen blow, which is the largest emissions source.

Primary1 Furnace Controls. Emissions during oxygen 

blow periods are controlled by the primary emissions 

capture and control system for the BOF, which is either: 

(1) an open hood directed to an ESP or wet scrubber, or (2) 

a closed hood ducted to a wet scrubber. There are about 

twice as many open as closed hood BOF shops in the U.S. 

EPA has reported that fabric fi lters have recently been 

1. In other chapters, “primary” is used as distinct from secondary (precursor) emissions. In this chapter, “primary” is used as distinct from 

fugitive emissions.

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proven effective, but they are not currently used at any 

facility in the U.S. (EPA, 2001a). The use of fabric fi lters 

could provide signifi cantly better PM control.

EPA also reported in 2001 that all BOFs had capture and 

control systems for primary emissions. Eight of the open 

hood systems had venturi scrubbers; another eight were 

controlled by ESPs. All eight of the closed hood shops 

were controlled by venturi scrubbers. EPA reported that 

ESPs at the open hood shops performed better than the 

venturi scrubbers (the MACT standard for open hood 

systems is therefore based on this technology). For closed 

hood systems, the MACT standard is based on highenergy venturi scrubbers with a pressure drop of 50 inches 

of water or more (EPA, 2001c).

Opportunities for improved control of primary emissions 

will vary from site to site; they typically include the 

potential for signifi cantly reduced emissions from 

upgrading old scrubbers to scrubbers with a higher 

pressure drop and upgrading ESPs.

Secondary Furnace Controls. According to EPA, 

data on secondary BOF emissions are extremely limited 

(EPA, 2001c). The BOF produces secondary or fugitive 

emissions—primarily metal oxides—when the molten 

iron and scrap metal are charged to the furnace and when 

the molten steel and slag are tapped from the furnace. 

Additional sources of secondary emissions include hot 

metal transfer, deslagging, and ladle metallurgy operations 

(EPA, 2001b, 2001c). Most plants have capture systems 

and baghouses for these other sources, and those that 

do not are logical candidates for installing them. A 

review of emissions tests should indicate if the baghouse 

is performing properly—a well designed and properly 

operated baghouse should achieve a PM emissions rate of 

less than 0.005 gr/dscf (EPA, 2005h). 

According to EPA, control options for secondary furnace 

Table 10.5

Pollution Control Devices at U.S. Sinter Plants

Plant

Capacity 

(million tons 

per year)

Control Device

Windbox Discharge Cooler

Mittal Steel (formerly ISG, Bethlehem Steel), Burns Harbor, IN 2.9 Scrubber Baghouse None

Mittal Steel (formerly ISG, Bethlehem Steel), 

Sparrows Point, MD 4.0 Scrubber Baghouse Cyclone

Mittal Steel (formerly Ispat Inland), East Chicago, IN 1.4 Baghouse Baghouse None

Mittal Steel (formerly ISG, LTV Steel), East Chicago, IN 1.9 Scrubber Scrubber None

US Steel, Gary, IN 4.4 Baghouse Baghouse None

Source: EPA, 2005b, updated October 2005
146 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

emissions include furnace enclosures, local hoods, full or 

partial building evacuation and—for open hood systems—

adapting the primary furnace hood to capture secondary 

emissions as well (this is an option for shops with relatively 

large fl ow capacity in the primary control system). PM 

removal techniques in use as of EPA’s 2001 NESHAP 

assessment included baghouses and wet scrubbers (EPA, 

2001a). EPA reported that about half of the BOF shops had 

a separate capture and control system for emissions from 

BOF charging and tapping. Ten of these used baghouses 

and the other two used scrubbers. The other half relied 

on the primary collection system to capture some of the 

emissions (EPA, 2001c). For those shops that rely on the 

primary collection system, adding secondary collection 

systems would provide signifi cant additional pollution 

control (EPA, 2001a).

Summary of World Bank and European 

Commission Recommendations. The World Bank 

and EC reports identify opportunities for controlling BOF 

emissions. These are summarized below (World Bank, 

1998a; EC, 2001). 

Use enclosures around the BOF.

Use effi cient evacuation and subsequent purifi cation 

by a fabric fi lter or ESP during hot metal 

pretreatment (including hot metal transfer processes, 

desulfurization and deslagging).

Recover BOF gas to use as fuel.

“De-dust” primary emissions through suppressed 

combustion and dry electrostatic precipitation (in 

new or existing situations) or scrubbing (in existing 

situations).

Cover the lance hole during oxygen blowing and 

inject inert gas to dissipate the PM.

“De-dust” secondary gases (emissions that cannot 

be captured effectively by the primary ventilation 

system) during charging, tapping, hot metal handling 

(reladling operations), deslagging of hot metal, and 

secondary metallurgy by using effi cient evacuation 

followed by fabric fi ltration or use of an ESP. These 

techniques can achieve a capture effi ciency of about 

90 percent.

Suppress fumes with inert gases during reladling of 

hot metal.

Sinter Plants

Of the fi ve sinter plants in the U.S., three use a baghouse to 

control windbox exhaust, while the other two use a venturi 

scrubber (Branscome, 2005a). When developing MACT 

standards in 2001, EPA determined that both baghouses 

and venturi scrubbers were capable of achieving the 

MACT fl oor level and that no other control devices could 

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•

achieve better emissions control (EPA, 2001c). At the 

discharge end, emissions are controlled by local hooding 

and ventilation to one or more baghouses or wet scrubbers. 

Four sinter plants in the U.S. use baghouses and one uses 

a wet scrubber (Branscome, 2005a; EPA, 2001a). Finally, 

while all the plants operate sinter coolers to cool the sinter 

product prior to storage, only one has a control device. 

This plant vents to a cyclone, while the others vent directly 

to the atmosphere (EPA, 2001a).

Requiring the other four plants to install control devices 

for their coolers thus represents the most signifi cant 

emissions reduction opportunity at sinter plants in the 

U.S. The coolers can be a signifi cant source of PM 

emissions (several hundred tons per year), because of the 

high volumetric fl ow rate and PM loading. Two plants 

that recently closed had baghouses, but currently only one 

controlled cooler remains (Branscome, 2005a). 

Table 10.5 shows the pollution control devices in operation 

at the fi ve sinter plants in the U.S.

The EC has identifi ed a number of opportunities for 

further pollution reductions at sinter plants in addition to 

baghouses and scrubbers (EC, 2001).

Sinter plants can cut SO2 emissions by:

Reducing the sulfur content of the sinter feed; in 

particular, reducing the sulfur content of the coke 

breeze, which consists of small-grade coke with 

particle sizes under 5 millimeters (mm).

Making the sinter feed more basic (as opposed to 

acidic).

Using coarser coke breeze (5–6 mm) instead of 

normal grain sizes (under 3 mm). One plant achieved 

a 40 percent reduction in SO2 emissions.

Using regenerated activated carbon (RAC) for 

desulfurization. The RAC process allows several 

components—including SO2, hydrogen chloride, 

hydrogen fl uoride, mercury, and sometimes, 

depending on the design, NOx—to be removed from 

the waste gas. SO2 may be reduced by more than 

95 percent, while nitrogen control effi ciency can be 

as high as 80–90 percent, depending on operating 

temperature, ammonia addition and design.

Focusing controls on the end of the strand, closest to 

the sinter cooler, since emissions increase along the 

sinter strand where temperatures are higher.

Plants can also reduce energy use by reusing the waste heat 

from the main exhaust gas from the sintering machines or 

by reusing cooling air from the sinter cooler.

•

•

•

•

•
 Chapter 10 - Iron and Steel 147

Minimills

In an EAF, charging and melting scrap and tapping steel 

all generate emissions of metal dust and gaseous products. 

Iron oxides are the primary component of resulting PM 

emissions, although the composition of the PM varies 

depending on the composition of the scrap metal and other 

materials that are used. SO2 and NOx are generated in 

addition to PM (EPA, 2004c).

In general, most minimills in the U.S. are controlled 

to some degree, because the applicable New Source 

Performance Standards (NSPS) were developed over 

three decades ago. Since then, they have been updated 

only once, in 1984. Minimills have expanded rapidly as a 

result of modifi cations and new plants and have therefore 

become increasingly subject to the NSPS. 

During melting, plants control primary emissions by using 

a shell to carry emissions to a baghouse. All but one plant 

in the U.S. use a baghouse to control primary emissions 

from melting, and each of those can meet the NSPS of 

0.0052 gr/dscf. The one plant without a baghouse uses a 

wet scrubber and has an emissions rate approximately ten 

times higher than the NSPS (Branscome, 2005b).

Fugitive emissions from charging, tapping, and melting 

are controlled with baghouses at all plants. Ten plants 

are not subject to opacity limits for fugitive emissions as 

stringent as the NSPS (6 percent opacity). Most of these 

plants would have to upgrade to meet the NSPS limit for 

fugitive emissions. Cost information for improved capture 

systems is not currently available, but EPA is developing 

the information and plans to publish it by early 2006 

(Branscome, 2005b). 

All but one minimill in the U.S. also use hoods and 

baghouses to control emissions from the ladle metallurgy 

process and from the argon oxygen decarburization vessel 

(a processing unit used to produce specialty steels). The 

Table 10.6

NSPS for Iron and Steel Plants (40 CFR §§60.140, et seq. (subpart N), §§60.140a, et seq.

(subpart Na), §§60.270, et seq. (subpart AA), and §§60.270a, et seq. (subpart AAa))

Source Applicable Datea Unit PM Opacity (percent)

Primary emissions 

from BOFs

After June 11, 1973 Any 50 mg/dscm 

(0.022gr/dscf)b

10c

After January 20, 1983 Open hood 50 mg/dscm 

(0.022gr/dscf)

10c

Closed hood 68 mg/dscm 

(0.030 gr/dscf)

10c

Secondary 

emissions from 

basic oxygen steel 

making facilities

After January 20, 1983 BOF shop roof monitor or 

other openings

NA 10c

Control device used only for 

secondary controlsd

23 mg/dscm 

(0.010 gr/dscf)

5

EAFs Between October 11, 

1974 and August 17, 

1983

Control device 12 mg/dcsm 

(0.0052 gr/dscf)

3

Shop NA 6e

Dust-handling equipment NA 10

EAFs and 

argon-oxygen 

decarburization 

vessels

After August 17, 1983 Control device 12 mg/dscm 

(0.0052 gr/dscf)

3

Shop NA 6

Dust-handling equipment NA 10

NA = No applicable standards

a. The applicable date is the date after which units commenced construction, modifi cation, or reconstruction.

b. Mg/dscm = milligrams per dry standard cubic meter; gr/dscf = grains per dry standard cubic foot.

c. Opacity between 10 and 20% may occur once per steel production cycle.

d. Fume suppression systems used to control secondary emissions and control devices used to collect both primary and secondary 

emissions from a BOF are not subject to these limits.

e. There are various exceptions to the 6 percent rule (e.g., during charging and tapping periods).

Source: EPA 2000b, 2000c, 2005g, 2005h
148 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

one plant that does not—the same plant mentioned above 

that lacks a baghouse—evacuates its emissions from the 

argon oxygen decarburization vessel to the same scrubber 

it uses to control primary melting emissions (EPA, 2004c).

One option for achieving further emissions reductions is to 

introduce a Fuchs shaft furnace, which preheats the scrap 

and uses positioning techniques to reduce air emissions, 

including PM. These types of furnaces are in operation 

in Arizona, the United Kingdom, China, Malaysia and 

Turkey (Environment Canada, 2002).

EAFs may also employ the Consteel process. Developed 

in the mid-1980s, this process continuously charges scrap 

to the furnace via an enclosed conveyor system, thereby 

reducing PM emissions. Moreover, the hot furnace waste 

gases move in the opposite direction from the scrap and 

transfer heat energy to the scrap. A number of plants in 

the U.S. and Japan use the Consteel process (DOE, 1994; 

Environment Canada, 2002; Worrell, 1999).

In addition, minimills can take a variety of steps to cut 

energy use, which may not directly reduce PM2.5 emissions 

onsite but will reduce electricity use and its associated 

emissions. A number of possibilities are outlined in a 1999 

report by the Lawrence Berkeley National Laboratory, 

“Energy Effi ciency and Carbon Dioxide Emissions 

Reduction Opportunities in the U.S. Iron and Steel Sector.” 

For instance, using foamy slag to cover the arc and melt 

surface (to reduce heat losses), using direct current arc 

furnaces instead of conventional alternating current, and 

preheating scrap by using waste heat are measures that all 

save signifi cant energy (Worrell, 1999).

As discussed in other sections, the World Bank and the EC 

have also put forth suggestions concerning best available 

emissions control technologies for minimills (World Bank, 

1998a; EC, 2001). Their suggestions include:

Locate EAFs in enclosed buildings. 

Control dust by using fabric fi lters, direct offgas extraction, hood systems, dog-houses (so 

called because of their appearance), total building 

evacuation, and bottom tapping. For primary and 

secondary emissions from EAFs, up to 98 percent 

collection effi ciency is achievable. Moreover, 

minimizing dust also reduces heavy metal emissions 

(except for those present in the gas phase, such as 

mercury).

Preheat scrap to recover waste heat from off gas.

Improve feed quality by using selected scrap.

Reduce NOx emissions by using natural gas as fuel, 

low-NOx burners, and hydrogen peroxide and urea in 

stainless steel pickling baths.

•

•

•

•

•

Regulatory Authority

As indicated in Chapter 4, states and the federal 

government share responsibility for regulating criteria 

pollutants (e.g., PM2.5, SO2, NOx) from stationary sources 

like those operating at iron and steel plants. The federal 

government has more of the burden of regulating air toxics 

but—for both conventional and toxic types of pollution—

states and localities are free under federal law to adopt 

more stringent standards than the Clean Air Act requires. 

The sections that follow review federal standards that 

apply under the Clean Air Act to emissions from iron and 

steel plants. 

Reasonably Available Control Technology

State Implementation Plans (SIPs) for nonattainment areas 

must include Reasonably Available Control Technology 

(RACT) for new and existing sources. RACT standards are 

non-binding federal guidelines; for VOCs, the guidelines 

are known as Control Technique Guidelines (CTGs). 

Guidelines known as Alternative Control Techniques 

(ACTs) outline the control technologies that are available 

to address NOx emissions from specifi c source sectors, but 

do not specify actual RACT limits. There are no sectorspecifi c ACTs or CTGs for SO2, PM10 or PM2.5.

The ACTs applicable to NOx emissions from iron and 

steel mills can be found at www.epa.gov/ttn/catc/products.

html#aptecrpts (EPA, 2005j).

New Source Performance Standards

The NSPS apply to new, modifi ed and reconstructed 

sources in specifi c source categories, in both attainment 

and nonattainment areas. 

The requirements of 40 CFR §§60.140, et seq. (subpart N) 

apply to primary emissions from BOFs that commence 

construction, modifi cation, or reconstruction after June 11, 

1973.

The requirements of 40 CFR §§60.140a, et seq. (subpart 

Na) apply to secondary emissions from BOF steel making 

facilities that commence construction, modifi cation, or 

reconstruction after January 20, 1983.

The requirements of 40 CFR §§60.270, et seq. (subpart AA) 

apply to EAFs that commenced construction, modifi cation, 

or reconstruction after October 21, 1974 and on or before 

August 17, 1983.

The requirements of 40 CFR §§60.270a, et seq. (subpart 

AAa) apply to EAFs and Argon-Oxygen Decarburization 

vessels that commence construction, modifi cation, or 

reconstruction after August 17, 1983.
 Chapter 10 - Iron and Steel 149

The NSPS for these sources at iron and steel plants appear 

in Table 10.6. 

Regional Haze/Best Available Retrofi t 

Technology

Under the regional haze program, Best Available 

Retrofi t Technology (BART) requirements apply, in both 

attainment and nonattainment areas, to PM2.5 and PM2.5-

precursor emissions from large sources in 26 identifi ed 

source categories that began operation between 1962 and 

1997. The source categories include iron and steel mill 

plants, coke oven batteries, and sintering plants. States 

have not yet developed their BART rules.

New Source Review/Prevention of Signifi cant 

Deterioration 

New Source Review (NSR) and Prevention of Signifi cant 

Deterioration (PSD) requirements apply to new and 

Table 10.7

Recent BACT Determinations for Steel Millsa

Minimill (Electric Arc Furnace)

Permit 

Date

Date of Last 

Determination

Process Pollutant Control Effi ciency (%)

Wheeling Pittsburgh Steel, Jefferson County, Ohio

6-Jan-05 12-Aug-05 EAF material 

handling 

PM10 Baghouse and vent fi lters 99

LMF material 

handling 

PM10 Baghouse and vent fi lters 99

Rocky Mountain (CF & I Steel), Pueblo, Colorado

21-Jun-04 20-Jan-05 EAF PM10 High-effi ciency fi lter baghouse 

PM Fabric fi lter

SO2 Alternative raw materials and 

process controls

Quanex Corporation, Jackson, Michigan

8-Dec-03 13-Oct-05 EAF PM10 Side draft/canopy hood and 

baghouse

99.90

North American Stainless, Montgomery, Indiana

21-Nov-03 6-Feb-04 Ladle metallurgy PM Baghouse

EAF dust treatment Scrubber

EAF dust handling Bin vents

AOD NOx Natural gas fi red oxy fuel burners 

Nucor Steel Decatur, Morgan, Alabama

7-Jul-02 25-Aug-03 EAF PM Baghouse 99

Integrated Steel Mill

Permit 

Date

Date of Last 

Determination

Process Pollutant Control Effi ciency (%)

Wheeling Pittsburgh Steel, Jefferson County, Ohio

6-Jan-05 12-Aug-05 BOF (material 

handling)

PM10 Baghouses 99

BOF PM Wet venturi scrubber, combustion 

hood and fl ame suppression

99

BOF (fugitive emissions) Baghouse and bin vent fi lters 99

Continued on next page
150 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

modifi ed large stationary sources in nonattainment and 

attainment areas, respectively. Under these programs, 

plants in nonattainment areas are subject to Lowest 

Achievable Emission Rate (LAER) standards, while plants 

in attainment areas are subject to Best Available Control 

Technology (BACT) requirements. Neither BACT nor 

LAER standards are codifi ed because they are intended to 

refl ect technology advancements as they occur.

EPA’s RACT/BACT/LAER Clearinghouse has information 

on BACT determinations since 2000 for a number of 

minimills, a coke plant, and an integrated iron and steel 

mill (See Table 10.7). The Clearinghouse does not have 

information on any LAER determinations for iron and 

steel plants.

Past BACT determinations for minimills—only some 

of which are included in Table 10.7—generally include 

a baghouse to control PM10 emissions from identifi ed 

emissions points; in addition, some also require vent fi lters 

and canopy hoods. The coke plant BACT determination 

requires pollution controls during charging, pushing, 

loading, handling and conveying. The PM10 controls 

involve a baghouse, while SO2 and NOx are controlled by a 

scrubber and staged combustion, respectively. Finally, the 

BACT determination for an integrated steel mill requires a 

baghouse, wet venturi scrubber and fl ame suppression to 

control PM10 and PM (including particles larger than PM10) 

Table 10.7 (continued)

Recent BACT Determinations for Steel Millsa

Coke Plant

Permit 

Date

Date of Last 

Determination Process Pollutant Control Effi ciency (%)

Haverhill North Coke Company, Scioto County, Ohio

27-Feb-01 14-Aug-03 Coking SO2 Dry scrubber, lime spray dryer, and 

low-sulfur coal

92b

NOx Staged combustion 85c

PM10 Baghouses 99

Charging PM10 Baghouse with traveling hood 93

Pushing PM10 Baghouse with a shed extending the 

length of the battery to capture all 

emissions

98

Loading PM Load-in coal, coke and coke breeze 

with stacking tube; load-in coal with 

water sprays or dust suppressant; 

load-out coal under pile gravity feed 

and water spray; load-out coke with 

under pile gravity feed

70-95d

Handling PM10 Rail car to use bottom dumping and be enclosed; 

belt conveyors to be enclosed; wet and/or chemical 

suppression

Coke breeze 

crushing/screening/

conveying

PM10 Baghouse

a. All determinations are for PSD (BACT), not NSR (LAER).

b. Also, 0% leakage and negative pressure in oven.

c. Also, no visible emissions from waste gas piping and 0% leakage from coke oven doors.

d. Depending on the emissions point.

Source: EPA, 2005b
 Chapter 10 - Iron and Steel 151

from identifi ed BOF-related operations.

Maximum Achievable Control Technology

MACT standards address emissions of HAPs from new 

and existing sources in identifi ed industry categories 

in both attainment and nonattainment areas. MACT 

standards apply to sources with potential emissions of 

10 tons per year of a single HAP or 25 tons per year of 

combined HAPs. In some MACT rules, such as those 

referenced here, EPA regulates PM as a surrogate for 

HAPs.

MACT Standards for Coke Oven Leaks. Under 40 

CFR §§63.300, et seq. (subpart L), visible emissions limits 

(opacity standards) apply to doors, lids, offtake systems 

and charging operations for new and existing coke oven 

batteries.

The MACT standard for coke oven leaks offers existing 

facilities two options: a MACT and a LAER track. The 

LAER track exempts existing facilities from a residual risk 

standard until 2020 but requires them to meet standards, 

some of which are more stringent and apply earlier than 

the MACT standards. Table 10.8a summarizes emissions 

limits for existing coke oven batteries under both tracks. 

A battery is considered “new” if it commenced 

Table 10.8a

Existing Byproduct Batteries

 MACT track limits (percent) LAER extension track limits (percent)

12/31/95 1/1/03 7/14/05a 11/15/93 1/1/98 1/1/10

Tall doorsb 6.0 5.5 4.0 7.0 4.3 4.0

Short doors (or otherwise exempted 

from tall door standards)b

5.5 5.0 3.3 7.0 3.8 3.3

Topside port lidsb 0.6 0.6 0.4 0.83 0.4 0.4

Offtake systemsb 3.0 3.0 2.5 4.2 2.5 2.5

Visible emissions per chargec 12 seconds 12 seconds

Table 10.8b

New and Rebuilt Byproduct Batteries

Emissions points

New or greenfi eld batteriesd

(percent)

Brownfi eld or padup rebuildd batteries 

(percent)

Same technology New technologye MACT track limits LAER extension track

Tall doorsb 0.0 4.0

Same as for existing 

batteries (see Table 

10.8a)

4.0

Short doors (or otherwise 

exempted from tall door 

standards)b

NA 3.3 3.3

Topside port lidsb 0.0 0.4 0.4

Offtake systemsb 0.0 2.5 2.5

Visible emissions per chargec 34 seconds 12 seconds 12 seconds

NA = No applicable standards

a. Residual risk standard, fi nalized April 15, 2005 (EPA, 2005e).

b. Based on a 30-run rolling average of percent leak.

c. Based on the logarithmic 30-day rolling average.

d. New and greenfi eld batteries cannot qualify for the LAER extension track and must meet the residual risk standard (shown in Table 

10.8a).

e. Padup rebuild means a coke oven battery that is a complete reconstruction of an existing coke oven battery on the same site and pad, 

as of November 15, 1990, without an increase in design capacity.

f. EPA determines case-by-case limits, which must be more stringent than the limits shown, or less than the equivalent level of mass 

emissions.

Source: EPA 2005f
152 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 10.9

MACT Standards for Integrated Iron and Steel Plants (40 CFR §§63.7780, et seq. (subpart 

FFFFF) and Coke Ovens (40 CFR §§63.7280, et seq. (subpart CCCCC))

Type of Plant Unit New or Existing PM Limit

Opacity Limit 

(percent)

Integrated 

iron and steel 

manufacturing 

facilities

Sinter Windbox exhaust stream New 0.3 lb/ton 

product sinter

Existing 0.4 lb/ton 

product sinter

Discharge end New 0.01 gr/dscfa 10b

Existing 0.02 gr/dscf 20b

Cooler stack New 0.01 gr/dscf

Existing 0.03 gr/dscf

Blast furnace Casthouse New 0.003 gr/dscf 15b

Existing 0.01 gr/dscf 20b

Basic oxygen 

furnacec

Primary emissions control 

system – closed hood

New and Existing 0.03 gr/dscf

Primary emissions control 

system –open hood

New 0.01 gr/dscf

Existing 0.02 gr/dscf

Secondary emissions control 

system

New 0.0052 gr/dscf

Existing 0.01 gr/dscf

Hot metal transfer, skimming, 

or desulfurization

New 0.003 gr/dscf

Existing 0.01 gr/dscf

Ladle metallurgy New 0.004 gr/dscf

Existing 0.01 gr/dscf

Roof monitor New 10d

Existing 20e

Coke ovens Cokeside 

shed

New 

or 

Existing

0.01 gr/dscf

Moveable 

hood 

Vented to a stationary control 

device

0.02 lb/ton 

coke 

Mobile 

scrubber carsf

Short batteries 0.03 lb/ton coke

Tall batteries 0.01 lb/ton coke

Mobile 

scrubber 

carsg

0.04 lb/ton coke

Battery stack Normal coking cycle 15h

Extended coking 10h

a. Mg/dscm = milligrams per dry standard cubic meter; gr/dscf = grains per dry standard cubic foot.

b. Six-minute average.

c. Basic oxygen furnace includes both top and bottom blown furnaces, but does not include argon oxygen decarburization furnaces.

d. Three- or six-minute average; opacity level may reach up to 20% for one period per each steel production cycle.

e. Three-minute average.

f. Not capturing emissions during travel.

g. Capturing emissions during travel.

h. Daily average.

Source: EPA, 2003, 2005i
 Chapter 10 - Iron and Steel 153

construction or reconstruction as of November 15, 1990. 

Table 10.8b shows the emissions limits for new and rebuilt 

batteries.

Finally, fugitive emissions from sources built on or after 

August 9, 2004 are subject to an opacity limit of 20 percent 

and a PM limit from charging emissions control devices 

under 0.0081 pounds per ton (lb/ton) of dry coal charged.

MACT Standards for Integrated Iron and Steel 

Plants. PM emissions from integrated iron and steel 

manufacturing facilities are regulated by 40 CFR 

§§63.7780, et seq. (subpart FFFFF). In particular, the 

subpart covers emissions from sinter plants, blast furnaces 

and BOFs. A unit is considered an “existing unit” if 

construction or reconstruction commenced before July 

13, 2001; a “new unit” is one for which construction or 

reconstruction commences on or after July 13, 2001.

PM emissions from coke ovens are regulated under 40 

CFR §§63.7280, et seq. (subpart CCCCC). In particular, 

it covers emissions from pushing, quenching and battery 

stacks. A unit is considered “existing” if it commenced 

construction or reconstruction before July 3, 2001; a “new 

unit” is one for which construction or reconstruction 

commences on or after July 3, 2001.

The MACT standards for these sources at iron and steel 

plants appear in Table 10.9. 

As a result of MACT requirements, a number of plants 

have installed new or improved emissions control systems. 

For instance, Indiana’s ISG Burns Harbor plant is in the 

process of installing two new baghouses for its blast 

furnaces, a new baghouse for the BOF vessels, and broken 

bag detectors and monitoring equipment. Ispat Island in 

East Chicago, Illinois is currently upgrading the scrubber 

at its BOF (Perry, 2005).

In addition, EPA proposed amendments to the MACT 

standards for integrated iron and steel manufacturing 

facilities on August 30, 2005, in response to a lawsuit 

brought by several steel companies. The revised limits 

would apply to each sinter cooler instead of to each sinter 

cooler stack and would set a 10 percent opacity limit 

instead of the current PM emissions limit of 0.03 gr/dscf. 

The proposal would also revise the operating limit for 

an ESP that controls emissions from a BOF; specifi cally, 

it would require that the hourly average opacity of 

emissions from the control device be maintained at or 

below 10 percent. Finally, the proposed amendments 

would reduce the frequency of performance tests, allow 

alternative monitoring systems, and change operating and 

maintenance plans (EPA, 2005c).

Clean Air Interstate Rule

None of the sources operating at iron and steel mills that 

are discussed here can be included in any of the federal 

Clean Air Interstate Rule (CAIR) trading programs 

without disqualifying the state from participation in 

federal trading regimes.

State and Local Initiatives

The federal MACT standards for coke plants and for 

integrated iron and steel plants require self-monitoring. 

It is important for local and state agencies to ensure that 

facilities adhere to the self-monitoring requirements, 

including reporting the data to the permitting agency.

In addition, a number of coke and steel plants have 

received compliance extensions for meeting MACT 

standards. To the extent possible, areas should limit 

compliance extensions to the absolute minimum.

In terms of states and localities imposing standards 

stricter than the federal standards, Allegheny County, 

Pennsylvania stands at the forefront. Most importantly, 

the Allegheny regulations set instantaneous limits for 

visible emissions from doors, charging, lids, and offtake 

systems, as well as for PM emissions from pushing and 

combustion stacks. The federal MACT standards are 

based on an average (usually 30 days or runs) (ACHD, 

2005; EPA, 2005f). Instantaneous standards coupled with 

frequent inspections by Allegheny County staff prevent 

Allegheny coke plants from delaying action to correct 

problems (Westman, 2005).

To comply with these stricter regulations, coke plants in 

Allegheny County employ both technology measures and 

work practice standards. In terms of technology, the coke 

plants use either a stationary shed or a moving hood, either 

of which evacuates pushing emissions to a baghouse. 

These options are equally effective at emissions reduction. 

(While stationary sheds have the added benefi t of also 

capturing door emissions, doors may experience more 

leaks because they are not easily visible and may not be 

cleaned or repaired as readily with a shed in place.)

It is also extremely important that coke plants use effective 

operational practices. Workers at the Allegheny plants 

undergo extensive training on door cleaning, sealing, lid 

operation, pollution control device management, and 

various other operations in the coke plant, and there is 

substantial oversight of workers’ performance (Westman, 

2005).

The U.S. Steel plant in Allegheny County represents 

an interesting case study of options for controlling SO2

emissions from coke plant operations. A few years after 

the Allegheny County Health Department established 
154 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

a hydrogen sulfi de (H2S) standard of 40 grains per 100 

dry standard cubic feet (40 gr/100dscf) for desulfurized 

coke oven gas, pressure mounted on U.S. Steel to reduce 

emissions further because of lingering odor issues and the 

region’s PM problem. In response, U.S. Steel authorized 

plant operators to do what they thought necessary to 

achieve emissions under 30 gr/100dscf. The operators 

installed more sensitive controls and better instruments 

to improve their understanding of all emissions points 

and engaged in a number of fi ne-tuning operations to 

achieve the 30 gr/100 dscf goal. With the success of the 

“Under 30” program, U.S. Steel implemented a similar 

challenge for an “Under 20” program to make even further 

emissions reductions to under 20 gr/100 dscf. The plant 

now produces coke oven gas with H2S levels between 15 

and 20 gr/100dscf (Westman, 2005).

Allegheny County is also home to U.S. Steel’s Edgar 

Thomson plant, which uses an entirely enclosed BOF. 

Designed as a closed-in structure two decades ago to 

deal with the area’s “dustfall” PM problem, the plant has 

reduced fugitive emissions substantially using primary and 

secondary emissions controls (baghouses). However, the 

plant continues to generate some fugitive emissions from 

leaking side doors and a roof.

Indiana has a number of regulations for both coke plants 

and integrated iron and steel mills that impose standards 

stricter than the federal MACT requirements. For instance, 

in the case of coke plants, Indiana has set opacity limits 

for bypass heat exchanger stacks and for pushing controls, 

whereas the MACT standards have no opacity limits (Kuh, 

2001a). Likewise, in the case of integrated iron and steel 

mills, Indiana has established opacity limits for BOFs, 

whereas the federal MACT standards require only that 

site-specifi c opacity limits be developed during initial 

performance tests on ESPs controlling BOF emissions. 

Finally, Indiana regulates both the oil and grease content of 

sinter plant feedstock, while the federal MACT standards 

regulate only oil content (Kuh, 2001b).

The state of Michigan has a regulatory scrap management 

program for iron and steel plants. While the primary 

goal of the program is to reduce mercury emissions by 

removing switches from automobiles, the program also 

cuts SO2 emissions by requiring that scrap be clean and 

free of oily residues. This approach is also useful for 

reducing emissions of condensable particulate emissions 

caused by melting oily scrap.

References

Ailor, David C., American Coke and Coal Chemicals 

Institute. “Principal Environmental Issues Facing the U.S. 

Coke Industry in 2003,” Met Coke World Summit 2003, 

October 8, 2003. www.accci.org/Ailor.pdf.

Aker Kværner ASA. HIsmelt Kwinana Direct Iron 

Smelting Project, accessed August 1, 2005, from: www.

akerkvaerner.com/Internet/MediaCentre/Featurestories/

MiningMetals/HIsmelt.htm.

Allegheny County Health Department (ACHD). “Coke 

Ovens and Coke Oven Gas,” Rules and Regulations, 

Article XXI: Air Pollution Control, §2105.21, June 13, 

2005.

Boselovic, Len, and D. Hopey. “Indiana Plant To Make 

Coke, Power,” Pittsburgh Post-Gazette, February 20, 1998. 

www.postgazette.com/businessnews/19980220bcoke2.asp.

Branscome, Marvin, Research Triangle Institute. Personal 

communication with M.J. Bradley & Associates. List 

of iron and steel plants; updated based on press releases, 

November 1, 2005. (2005a)

Branscome, Marvin, Research Triangle Institute. 

Personal communication with M.J. Bradley & Associates. 

Discussion of emissions control options for integrated iron 

and steel plants and electric arc furnaces, November 1, 

2005. (2005b)

Burns, S., Research Triangle Institute. “Memorandum 

to docket enclosing data compiled from EPA Section 

114 survey responses,” National Emission Standards 

for Hazardous Air Pollutants for Coke Ovens: Pushing, 

Quenching, and Battery Stacks; Final Rule (Docket Item 

II-I-45 in Docket EPA-HQ-OAR-2002-0085), July 1998.

Davis, W., Air & Waste Management Association. Air 

Pollution Engineering Manual: Second Edition, 2000.

Environment Canada. Environmental Code of Practice for 

Integrated Steel Mills–CEPA 1999 Code of Practice, 1999. 

www.ec.gc.ca/nopp/docs/cp/1mm7/en/c2.cfm#d.

Environment Canada and the Canadian Council of 

Ministers of Environment. Multi-pollutant Emission 

Reduction Analysis Foundation (MERAF) for the Iron and 

Steel Sector, prepared by Charles E. Napier Company Ltd., 

September 11, 2002.

European Commission (EC). Integrated Pollution 

Prevention and Control (IPPC) Best Available Techniques: 

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 Chapter 10 - Iron and Steel 155

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10, 2005, from: www.apec-egcfe.org/Cebu_2005/session_

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Requirements), September 26, 2001. (2001a)

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2001. (2001b)

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& Associates, December 15, 2005.

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Plant” Siemens Press Release, June 10, 2005. www.vai.at/

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industry/steel/pdfs/steel_visionprofi le.pdf.

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25, 2005. www.fe.doe.gov/programs/projectdatabase/

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2005. http://minerals.usgs.gov/minerals/pubs/mcs/2004/

mcs2004.pdf

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after June 11, 1973,” 40 CFR §60.140, October 17, 2000. 

(2000b)

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CFR §60.140a, October 17, 2000. (2000c)

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156 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

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of Performance for Steel Plants: Electric Arc Furnaces 

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August 17, 1983,” 40 CFR §60.270, February 22, 2005. 

(2005g)

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Argon-Oxygen Decarburization Vessels Constructed after 

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(2005h)

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§63.7280, August 2, 2005. (2005i)

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Pollution Technical Reports,” Technology Transfer 

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2005. (2005j)

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 Chapter 10 - Iron and Steel 157

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the U.S. Iron and Steel Sector, July 1999. www.energystar.

gov/ia/business/industry/41724.pdf.
158 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Petroleum is the largest source of energy in the U.S., 

accounting for approximately 40 percent of the nation’s 

total energy consumption (EIA, 2003). Measured by 

energy content (i.e., British thermal units, or Btus, 

consumed), Americans use more petroleum than either coal 

or natural gas. Before petroleum can be used, however, it 

must fi rst go through an extensive refi ning process.

Using physical, thermal and chemical processes, petroleum 

refi neries separate crude oil into its major fractions, 

which are then processed further into fi nished petroleum 

products. The primary products of the industry fall into 

three major categories: fuels (gasoline, diesel, jet fuel); 

fi nished products (solvents, lubricating oils, asphalt); 

and chemical industry feedstocks (ethylene, propylene, 

butadiene). Fuels account for almost 90 percent of the 

petroleum products produced in the U.S., while fi nished 

products and petrochemical feedstocks each account for 

about 5 percent (EPA, 1995a).

The petroleum refi ning process involves a vast complex 

of operations, from desalting1

 and distilling2 to cracking 

(breaking down large hydrocarbons into smaller molecules) 

and polymerizing (combining small hydrocarbons to form 

larger molecules). Different refi neries may have slightly 

1. Crude oil often contains water, inorganic salts, suspended solids and 

water-soluble trace metals. Desalting is the process of removing these 

contaminants.

2. Distillation is the process of separating different petroleum products.

different sets of operations, in part because the composition 

of crude oil—a mixture of various hydrocarbons with 

differing amounts of impurities—varies substantially 

depending on its source. Also, refi neries serve different 

markets with different product needs. As a result, no two 

refi neries are exactly alike.

The petroleum refi ning industry consumes large amounts 

of energy derived from a variety of fuel sources. The 

industry obtains about 65 percent of the energy it consumes 

for heat and power from byproducts of the refi ning process, 

including refi nery gas, petroleum coke and other oil-based 

byproducts (DOE, 2000). Refi neries also rely on natural 

gas for a substantial share of their energy needs (DOE, 

Chapter 11

Petroleum Refi neries
 Chapter 11 - Petroleum Refi neries 159

2000).

The petroleum refi ning process produces a host of 

pollutants—including fi ne particulate matter (PM2.5), 

sulfur dioxide (SO2) and nitrogen oxides (NOx)—from the 

combustion of various fuels in boilers, process heaters, 

engines and fl ares. This chapter discusses technology 

and policy options for addressing these different sources 

of emissions. It addresses the refi ning process only and 

does not cover the exploration, production or transport of 

petroleum products.

Sector Profi le

A small number of large plants dominate the petroleum 

refi ning industry and an even smaller number of 

companies own and operate those plants. There are 

currently 144 refi neries in the U.S., concentrated in a 

relatively small number of states (EIA, 2005a). Table 11.1 

presents a summary of U.S. refi ning capacity by state. 

States with large numbers of refi neries are those that either 

possess crude oil sources (onshore petroleum terminals, 

oil and gas extraction areas) or many consumers (heavily 

industrialized areas). U.S. petroleum refi neries produce 

approximately $220 billion worth of products annually and 

employ 64,000 people (EIA, 2005b).

Over the past two decades, the refi ning industry has 

undergone substantial restructuring. In 1981, the 

government terminated the Crude Oil Entitlements 

Program, which had encouraged smaller refi neries. 

This forced the least effi cient plants to close. The 

1990s witnessed increasing industry consolidation and 

concentration, as a growing number of fi rms merged in 

order to reduce costs by sharing assets and minimizing 

operating costs. The number of major U.S. energy 

companies dropped from 19 in 1990 to nine in 2001; 

meanwhile the merger of Exxon and Mobil created the 

world’s largest publicly traded energy company. Of the 

300 refi neries that were in operation in 1982, only 176 

remained in 1994—and only 144 continue to operate 

today (EPA, 1995a; EIA, 2005a). Throughout this period, 

however, refi ning capacity did not diminish. In fact, 

even as 47 refi neries shut down during the 1990s, overall 

refi ning capacity increased 6 percent (EIA, 2002).

Emissions

A host of operations produce air emissions within the 

petroleum refi ning process; however, there are a few 

dominant sources. Table 11.2 provides an estimate of 

PM2.5, SO2 and NOx emissions from the petroleum refi ning 

industry by process category. The estimates are based 

on EPA’s 1999 National Emissions Inventory. Boilers, 

process heaters, and catalytic cracking units are dominant 

sources of PM2.5, SO2 and NOx emissions. Internal 

combustion engines and fl ares produce a more modest, but 

still signifi cant, share of PM2.5, SO2 and NOx emissions. 

Petroleum refi neries are also major sources of volatile 

organic compounds (VOCs), hazardous air pollutants (both 

organics and metals) and carbon monoxide (CO). These 

pollutants are not the focus of this report.

Catalytic cracking units are a major source of air pollution 

at refi neries. Emissions from catalytic cracking processes 

Table 11.1

Capacity and Number of Petroleum Refi neries by State

Rank State Capacity (thousand 

barrels/day)

% of Total U.S. 

Capacity

Number of 

Refi neries

% of Total Number 

of U.S. Refi neries

1 Texas 4,628 27% 25 17%

2 Louisiana 2,773 16% 17 12%

3 California 2,005 12% 21 15%

4 Illinois 896 5% 4 3%

5 Pennsylvania 770 5% 5 3%

6 Washington 616 4% 5 3%

7 New Jersey 615 4% 5 3%

8 Ohio 551 3% 4 3%

9 Oklahoma 485 3% 5 3%

10 Indiana 433 3% 2 1%

Subtotal 13,772 81% 93 65%

U.S. Total 17,006 100% 144 100%

Source: EIA, 2005a
160 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

come from two sources: process heaters and fl ue gas from 

catalyst regeneration. (Catalyst regeneration is the process 

by which catalysts are cleaned and restored after being 

contaminated in a reaction.) The catalyst regenerator 

emits particulates, SO2, NOx and other pollutants. Fluid 

catalytic cracking units are a particular concern because of 

their high rates of PM emissions (EPA, 1995b).

Sulfur compounds present in crude oil are converted 

to hydrogen sulfi de in the cracking and hydro treating 

processes. Many refi neries convert hydrogen sulfi de 

gas to elemental sulfur using a “Claus” sulfur recovery 

plant. The conversion process produces elemental sulfur, 

which can be sold for agricultural chemicals and other 

applications. The process also produces SO2 emissions. 

Petroleum refi neries use fl ares to combust vapors rather 

than discharging them directly to the atmosphere. The 

fl ares produce PM2.5, SO2 and NOx emissions. Steam may 

be injected into the fl are tip to reduce visible smoke.

Refi neries also produce signifi cant fugitive emissions. 

Fugitive emissions are generated by thousands of potential 

emissions sources, including valves, fl anges, pump and 

compressor seals, tanks and process drains. Evaporation 

of spilled petroleum liquids and gases also causes fugitive 

emissions. Generally, the control of fugitive emissions 

involves minimizing leaks and spills through equipment 

changes, procedure changes, and improved monitoring, 

housekeeping and maintenance practices (EPA, 1995a).

The Petroleum Refi ning Process

The petroleum refi ning process is often described in terms 

of fi ve basic steps: fractionation, conversion, treatment, 

formulation and blending, and auxiliary processes. 

Different refi neries perform some or all of these activities.

Petroleum refi ning begins with the crude, or unprocessed, 

oil that is pumped from the ground or ocean fl oor. Crude 

oil contains various elements or compounds, but the 

key components are carbon and hydrogen that form 

hydrocarbon molecules of different lengths and structures, 

from straight chains to branching chains and rings. 

Fractionation (distillation) is the separation of crude oil in 

atmospheric and vacuum distillation towers into groups 

of hydrocarbon compounds with differing boiling-point 

ranges, called fractions or cuts. Because of the large 

volumes of crude oil subjected to this initial processing 

step, atmospheric and vacuum distillation account for a 

signifi cant share (35–40 percent) of the energy a refi nery 

consumes (DOE, 2000).

Refi neries use cracking, reforming and other conversion 

processes that change the size and structure of the 

hydrocarbon molecules to convert most distillation 

products into more usable products. These processes break 

down longer chain molecules into smaller ones by heating 

or using catalysts.

The converted products are then subjected to various 

treatment and separation processes to remove undesirable 

constituents and improve product quality. Treatment may 

include the removal or separation of aromatics as well as 

impurities and undesirable contaminants, such as sulfur, 

nitrogen and heavy metals. It may involve chemical or 

physical separation (such as dissolving, absorption or 

precipitating) by means of a variety of processes, including 

Table 11.2

Petroleum Refi ning Sector Emissions (1999)

Process Type PM2.5 SO2 NOx

Tons/Year Percent 

of Sector 

Emissions

Tons/Year Percent 

of Sector 

Emissions

Tons/Year Percent 

of Sector 

Emissions

Boilers 9,437 26% 103,026 25% 70,260 29%

Internal combustion engines 1,515 4% 862 <1% 18,449 8%

Catalytic cracking units 9,646 26% 136,780 33% 29,603 12%

Process heaters 9,880 27% 71,789 17% 100,380 41%

Flares 394 1% 27,763 7% 8,503 3%

Cooling towers 1,706 5% -- -- -- --

Elemental sulfur production 7 <1% 18,872 5% 274 <1%

Other process related 4,145 11% 57,956 14% 16,288 7%

Total 36,729 100% 417,048 100% 243,757 100%

Source: EPA, 2005e (based on facilities listed under SIC code 2911)
 Chapter 11 - Petroleum Refi neries 161

desalting, drying, hydrodesulfurizing, solvent refi ning, 

sweetening, extracting solvents and solvent dewaxing.

Formulating and blending is the process of mixing and 

combining hydrocarbon fractions, additives and other 

components to produce fi nished products with specifi c 

performance properties. For example, refi ners combine 

different mixtures of hydrocarbons to produce gasoline 

with different octane ratings.

There are several auxiliary processes that are vital to 

the functioning of a petroleum refi nery, including power 

generation, solid waste and wastewater treatment, processwater treatment, and cooling and other utility services.

Petroleum refi neries use combustion equipment (e.g., 

boilers and process heaters) throughout the refi ning process 

to produce electricity, steam and heat. Process heaters 

fueled by refi nery gas (a byproduct of the refi ning process), 

natural gas, residual fuel oils or some combination thereof 

are used to produce the heat that is necessary in many 

of the refi ning processes (EPA, 1995b). Electric motors, 

steam turbines and internal combustion engines are used 

to drive pumps, compressors, blowers and other refi nery 

process equipment. Fuel combustion by these types of 

equipment is responsible for a signifi cant share of the 

refi nery sector’s PM2.5, SO2 and NOx emissions. 

Because of their coincident demand for electrical and 

thermal energy, petroleum refi neries are one of the nation’s 

largest users of combined heat and power technology 

(also known as CHP or cogeneration). CHP systems are 

integrated technologies that produce useful thermal and 

power output, thereby increasing the overall fuel effi ciency 

of the unit. CHP technologies also offer signifi cantly 

lower pollution emissions rates compared to separate heat 

and power systems.

Emissions Control Opportunities

Modern pollution control systems can reduce air pollution 

emissions from petroleum refi neries dramatically, as 

evidenced by the agreements that EPA has reached with 

several U.S. oil companies. Most recently, EPA and the 

Department of Justice announced an agreement with 

ExxonMobil to reduce NOx and SO2 emissions by 11,000 

tons per year and 42,000 tons per year, respectively, at the 

company’s seven U.S. petroleum refi neries (EPA, 2005d). 

According to EPA, companies that together account for 

nearly 77 percent of domestic refi ning capacity have 

agreed to legally binding agreements to reduce their air 

pollutant emissions (EPA, 2005d). Process changes, 

equipment upgrades, pollution control equipment, 

increased monitoring and better equipment maintenance 

are all options for controlling refi nery air emissions 

(Davis, 2000). Process heaters, boilers, catalytic cracking 

units and fl ares provide the primary opportunities for 

PM2.5, SO2 and NOx control.

Process Heaters

Virtually every step of the petroleum refi ning process 

relies on process heaters, but their main use is as preheaters 

for distillation, catalytic cracking, hydroprocessing and 

hydroconversion (EPA, 1993a). Process heaters raise the 

temperature of process materials for additional processing 

(heated feed) and drive chemical reactions in the process 

heater tubes (reaction feed). For example, process heaters 

preheat crude oil prior to distillation.

A process heater is an enclosed device in which solid, 

liquid or gaseous fuels are combusted for the purpose 

of heating a process material (e.g., crude oil). There are 

two basic types of process heaters: direct and indirect. 

Direct-fi red systems place the combustion gases in direct

contact with the process material. Indirect systems rely on 

tubing to separate the combustion gases from the process 

material. Indirect-fi red process heaters are similar to 

boilers, except that boilers heat water to produce steam 

rather than to heat process materials. The petroleum sector 

Table 11.3

Process Heater Emissions Rates

Fuel Emissions Rate (lb/MMBtu)

PM2.5 SO2 NOx

Distillate Oil 0.014 0.304 0.143

Residual Oil 0.026–0.046 0.628–1.047

(352–587 ppm)

0.367a

(286 ppm)

Refi nery gas no data 0.084 0.087

a. For process heaters over 100 million British thermal units per hour (MMBtu/hr). Process heaters under 100 MMBtu/hr have a NOx

emissions rate of 0.313 lb/MMBtu.

Source: EC, 2003; EPA, 1995b.
162 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

relies primarily on indirect-fi red process heaters. Process 

heaters are fueled by refi nery gas, natural gas, residual fuel 

oils or combinations thereof, depending on cost, operating 

conditions and emissions requirements. 

Several options are available for controlling emissions 

from process heaters, including fuel processing prior to 

combustion, fuel switching, combustion modifi cations and 

post-combustion controls.

Fuel processing is a common strategy used to control SO2

emissions from process heaters. A large portion of the 

fuel consumed by refi neries is generated internally by the 

different refi nery processes and collected in a refi nery 

gas system. Depending on the method of fuel processing 

used, refi nery gas contains varying amounts of sulfur. For 

example, refi nery gas produced by the crude distillation 

process contains higher concentrations of sulfur than 

refi nery gas produced by catalytic reforming. Higher 

sulfur refi nery gas is normally treated by amine scrubbing 

to remove hydrogen sulfi de before being released to the 

refi nery gas system.

Fuel switching is also an option for reducing emissions 

from process heaters. For example, SO2 emissions can be 

reduced by switching from liquid fuel oils to refi nery gas 

or natural gas. Several of the consent decrees stemming 

from EPA’s national petroleum refi nery compliance 

initiative require the affected facilities to discontinue the 

burning of fuel oil in all heaters and boilers, except in 

instances of natural gas curtailment, in an effort to reduce 

SO2 emissions. In some cases, the agreements further 

specify that only low-sulfur fuel oil be used during periods 

of natural gas curtailment (U.S. v. Valero, 2005).

Options are also available for controlling NOx emissions 

from process heaters. Natural gas and refi nery gas contain 

little or no fuel-bound nitrogen, but combusting these fuels 

at high temperature results in the formation of thermal 

NOx. The reaction of atmospheric nitrogen and oxygen in 

the combustion air produces thermal NOx. Firing refi nery 

fuel gas generally results in higher thermal NOx formation 

than fi ring natural gas due to the higher fl ame temperatures 

caused by the higher hydrogen content of refi nery gas 

(EPA, 1993a). Combustion of distillate and residual fuel 

oils results in the formation of both thermal and fuel NOx. 

According to EPA, low-NOx burners (LNBs), ultra-lowNOx burners (ULNBs), selective noncatalytic reduction 

(SNCR) and selective catalytic reduction (SCR) can be 

used to control NOx emissions from process heaters (EPA, 

1993a). Also, LNBs can be used in combination with fl ue 

gas recirculation (FGR), SNCR and SCR. Each of these 

control technologies is described in Chapter 5, Boiler 

Technologies. 

Companies have retrofi t many existing process heaters 

with low-NOx burners, allowing existing units to achieve 

NOx emissions rates in the range of 0.015–0.025 pounds 

per million British thermal units (lb/MMBtu) (Deason, 

2005). New process heaters are capable of NOx emissions 

rates in the range of 0.010–0.015 lb/MMBtu per hour 

(Deason, 2005). Few existing process heaters have been 

retrofi t with SCR controls, in part because of severe space 

constraints at petroleum refi neries. New process heaters, 

which allow greater fl exibility in terms of design and 

layout, are generally better suited to accommodate an 

SCR control system (Deason, 2005). Other factors may 

also limit the application of post-combustion controls. 

Refi nery process heaters are diverse in terms of their size, 

load and temperature duty. These factors will all infl uence 

the feasibility as well as the cost-effectiveness of available 

control options.

Table 11.4 provides estimates of the cost-effectiveness 

of alternative NOx control technologies for an averageTable 11.4

NOx Control Options for Refi nery Process Heaters

Technology Cost-Effectiveness ($/ton) by Capacity Factor

10% 50% 90%

Low-NOx burners 12,800–21,900 2,570–4,370 1,430–2,430

Ultra-low-NOx burners 8,830–14,800 1,770–2,950 981–1,640

Selective noncatalytic reduction 25,900–31,200 5,450–6,670 3,170–3,940

Selective catalytic reduction 71,900–80,100 14,800–16,400 8,460–9,370

Low-NOx burners with FGR 19,100–26,700 3,960–5,480 2,270–3,120

Low-NOx burners with SNCR 20,200–25,400 4,300–5,340 2,530–3,119

Low-NOx burners with SCR 69,300–74,100 14,200–15,200 8,110–8,640

Source: EPA, 1993
 Chapter 11 - Petroleum Refi neries 163

sized process heater (77 MMBtu per hour). The costeffectiveness of different control options varies depending 

on the utilization rate of the unit, as well as the type of 

process heater retrofi t.

Boilers

The petroleum refi ning industry also makes extensive use 

of boilers. Roughly 50 percent of the energy consumed 

by the sector is devoted to steam production (DOE, 

2002). Refi nery boilers are used primarily for heating and 

separating hydrocarbon streams and, to a lesser extent, for 

producing electricity. When used for heating, the steam 

usually heats the petroleum indirectly in heat exchangers 

and returns to the boiler. In direct contact operations, the 

steam serves as a stripping medium or a process fl uid. 

Refi nery boilers are fueled by refi nery gas, natural gas and 

residual fuel oils. 

There are three basic options for reducing PM2.5 and PM2.5-

precursor emissions from refi nery boilers: combustion 

controls, post-combustion controls and fuel switching. 

Chapter 6, Industrial and Commercial Boilers, provides a 

detailed discussion of the control options for industrial and 

commercial boilers.

Catalytic Cracking Units 

The catalytic cracking process converts heavier 

hydrocarbons into higher value, lower boiling point 

products—like gasoline and liquefi ed petroleum gas 

(LPG)—by combining the process feed (i.e., petroleum 

residues) with a catalyst at high temperatures. The inputs 

to the catalytic cracking process come from various parts 

of the refi nery, including the atmospheric and vacuum 

distillation units. The petroleum refi ning industry uses 

several types of catalytic cracking units; however, the 

fl uidized-bed reactor is the most common.

Catalytic cracking units produce PM2.5, SO2 and NOx 

emissions from several sources. First, process heaters and/

or waste heat from the catalyst regenerator unit (discussed 

below) pre-heat the oil-based residues that are sent to the 

catalytic cracking unit. The catalytic cracking process 

also relies on boilers. Steam is used to enhance the 

reactions of the process feed and the catalyst and to strip 

oil from the catalyst. The control technology options for 

process heaters and boilers are discussed above.

The primary source of emissions from the catalytic 

cracking process is the catalyst regenerator unit (EC, 2003). 

(The waste heat from the regenerator unit also provides 

much of the heat required by the catalytic cracking 

process.) During the cracking process, coke is deposited 

on the surface of the catalyst, deactivating the material. 

The catalyst is regenerated by burning off the coke at 

high temperatures. The fl ue gas from the regenerator unit 

contains PM2.5, SO2 and NOx (including catalyst fi nes), 

and other air pollutants. SO2 emissions from a catalytic 

cracking unit can range from 150 to 3,000 parts per million 

on a dry volume basis (ppmv), NOx emissions range from 

50 to 400 ppmv, and particulate emissions typically range 

between 200 and 650 milligrams per normal cubic meter of 

gas (Eagleson, 2005). The particles from the regenerator 

unit consist of silica/alumina and the nickel and vanadium 

present in the feedstock. Ninety percent of these particles 

are smaller than 10 micrometers (μm) in diameter (PM10) 

(EC, 2003). 

Cyclones and electrostatic precipitators (ESPs) are often 

used to control particulate emissions from regenerator 

units. Cyclones capture 30–90 percent of total particulates. 

However, cyclones are less effective at controlling PM10. 

ESPs can achieve control effi ciencies in excess of 95 

percent and are effective at capturing PM10. Baghouses are 

generally not used with catalytic cracking units because of 

the space required and because of the pressure drop they 

cause in the fl ue gas stream (EC, 2003).

Refi neries make widespread use of wet scrubbing for 

the simultaneous control of SO2 and particulates from 

regenerator units. A wet gas scrubber can achieve greater 

than 95 percent SO2 control and moderate NOx removal 

(70 percent) with the inclusion of an additional treatment 

tower. A wet gas scrubber can also reduce particulate 

emissions, although the technology is reported to be less 

effective for the control of smaller particles (EC, 2003).

Belco Technologies, a provider of air pollution control 

systems, reports that its EDV® wet scrubbing system can 

readily meet New Source Performance Standards (NSPS) 

for particulate and SO2 emissions (see Table 11.5). Testing 

performed at a U.S. refi nery found that the system was 

achieving greater than 99 percent SO2 removal effi ciency 

and greater than 92 percent particulate control (Eagleson, 

2005).

Several of the consent decrees arising from EPA’s refi nery 

enforcement initiative require the installation of wet gas 

scrubbers at fl uid catalytic cracking units. For example, 

Sunoco is required to install wet gas scrubbers at its 

Marcus Hook refi nery in Toledo, Ohio and at its refi nery 

in Philadelphia, Pennsylvania (U.S. v. Sunoco, 2005). 

The agreement further specifi es that SO2 concentrations 

be limited to 25 ppmv on an annual basis (at 0 percent 

oxygen). 

Refi neries also use SO2 adsorption catalysts to control SO2

emissions from regenerator units. A catalyst is added to 

the system, liberating the sulfur in the coke for capture 

in the refi nery’s amine scrubbing system. Controleffectiveness depends on the amount of the additive 

injected into the system.

NOx emissions can be reduced with SCR or SNCR 
164 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

controls. A modest but growing number of SCR systems 

have been installed at fl uid catalytic cracking units. The 

fi rst SCR control system installed in the U.S. on a fl uid 

catalytic cracking unit was at the ExxonMobil Torrance 

Refi nery in 2000 (U.S. v. ExxonMobil, 2005). Currently, 

the only SNCR installation at a catalytic cracking unit is in 

Japan (EC, 2003). However, several EPA consent decrees 

in the U.S. require the installation of SCR or SNCR 

controls at fl uid catalytic cracking units.

The BOC Group has developed a NOx control technology, 

known as LoTOxTM, that can achieve reductions 

comparable to those of an SCR system. LoTOxTM is a 

selective, low-temperature oxidation technology that uses 

ozone to oxidize NOx to water soluble nitric pentoxide, 

which reacts with moisture in the fl ue gas to form nitric 

acid. A wet scrubber then removes the oxidized NOx

compounds. The LoTOxTM technology is integrated within 

the EDV® wet scrubbing system discussed previously for 

simultaneous control of PM2.5, SO2 and NOx. The system 

reduces NOx emissions to 10 ppm or less (Sexton, 2004).

Sulfur Recovery Unit

The sulfur recovery process converts hydrogen sulfi de 

gas to elemental sulfur, which can be sold for other 

applications. SO2 emissions from the sulfur recovery 

process are directly related to recovery effi ciency. Higher 

recovery effi ciencies mean less sulfur is released to the air. 

Several factors infl uence the effi ciency of a sulfur recovery 

unit. In some cases, two or more catalytic stages are used 

in series to recover the sulfur. A two-bed catalytic Claus 

plant can achieve 94–96 percent effi ciency. A scrubber 

at the end of the recovery unit can capture the remaining 

sulfur compounds (EPA, 1993b).

Flares

Petroleum refi neries use fl ares to combust vapors rather 

than discharging them directly to the atmosphere. The 

fl ares produce PM2.5, SO2 and NOx emissions. They are 

used for non-steady-state operations, such as maintenance, 

startup, shutdowns and upsets. Some of these operations 

are predictable, while some are not. Flares provide an 

outlet for gases that might otherwise result in fi res or 

explosions and are therefore a critical component of the 

petroleum refi ning process. Flares also convert noxious 

and odorous gases to less hazardous gases. Frequent 

fl aring in routine, nonemergency situations or to bypass 

pollution control systems can produce excess emissions 

and may violate the Clean Air Act. 

In particular, the combustion of acid gases—a highly 

concentrated waste stream of hydrogen sulfi de gas and 

sour water stripper gas—can produce high rates of 

SO2 emissions. Typically, a refi nery relies on a sulfur 

recovery plant to process hydrogen sulfi de gas and sour 

water stripper gas to produce elemental sulfur for sale. 

According to EPA, a single day of acid gas fl aring can 

generate more SO2 than would be generated by an entire 

year of permitted sulfur recovery activity (EPA, 2000a). 

Improved operational control systems, improved training 

of operators, proper sizing of the sulfur recovery unit to 

handle all of the acid gases produced by the refi nery, and 

optimal performance of the sulfur recovery unit can all 

prevent the fl aring of acid gases (EPA, 2000a). In one case, 

a refi nery had been sending its acid gases to an adjacent 

chemical plant, resulting in the need to incinerate the 

gases when the chemical plant was unable to process them. 

Under a consent decree, the owner of the refi nery agreed to 

install a sulfur recovery plant at the refi nery to eliminate 

the problem (Sunoco, 2005). A refi nery in Oregon, Ohio 

was able to reduce its annual SO2 emissions from about 

180 tons to 49 tons through equipment and operational 

changes that eliminated conditions that had previously 

required higher rates of fl aring (EPA, 2000a).

Refi neries can also install fl are gas recovery systems to 

collect and treat refi nery gases, reducing the need for 

fl aring while at the same time recovering the gas for use 

in refi nery furnaces and boilers. Several such installations 

already exist in New Jersey, and California’s Bay Area Air 

Quality Management District (AQMD) has just issued a 

rule encouraging these systems (Bay Area AQMD, 2005a).

Regulatory Authority

As is the case for other stationary sources, state and local 

agencies share responsibility for regulating petroleum 

refi neries with the federal government. The federal 

government establishes two sets of emissions standards 

that apply to refi neries: NSPS for PM and SO2 emissions, 

and Maximum Achievable Control Technology (MACT) 

standards for hazardous air pollutants (HAPs).

Reasonably Available Control Technology

State Implementation Plans (SIPs) for areas that are in nonattainment of federal ambient air quality standards must 

include Reasonably Available Control Technology (RACT) 

requirements for new and existing sources. RACT 

standards are non-binding federal guidelines; for VOCs, 

the guidelines are known as Control Technique Guidelines 

(CTGs). Guidelines known as Alternative Control 

Techniques (ACTs) outline the control technologies that are 

available to address NOx emissions from specifi c source 

sectors, but do not specify actual RACT limits. There are 

no sector-specifi c ACTs or CTGs for SO2, PM10 or PM2.5.

ACT guidelines applicable to NOx emissions from 

equipment used at petroleum refi neries (e.g., boilers and 

process heaters) can be found at www.epa.gov/ttn/catc/

products.html#aptecrpts.
 Chapter 11 - Petroleum Refi neries 165

New Source Performance Standards

The NSPS typically apply to new, modifi ed and 

reconstructed sources in specifi c source categories in both 

attainment and nonattainment areas. 

The NSPS for petroleum refi neries are outlined in 40 CFR 

§§60.100, et seq. (subpart J). See Table 11.5 for refi nery 

NSPS standards for PM and SO2, as well as for applicable 

opacity limits. The standards apply to fl uid catalytic 

cracking unit catalyst regenerators and fuel gas combustion 

devices that commenced construction, reconstruction or 

modifi cation after June 11, 1973. They also apply to any 

Claus sulfur recovery plant of at least 20 long tons (22.4 

short tons) per day capacity that commenced construction, 

reconstruction or modifi cation after October 4, 1976.

In addition to the limits for PM and SO2 set forth in 

Table 11.5, the NSPS also require refi neries to limit the 

concentration of hydrogen sulfi de from any fuel gas 

combustion device (including during fl aring operations) 

constructed after June 11, 1973. Specifi cally, hydrogen 

sulfi de concentrations must be below 230 milligrams per 

dry standard cubic meter (0.10 grains per million dry 

standard cubic feet). Flaring hydrogen sulfi de can produce 

high ambient concentrations of SO2. This standard does 

not apply if there is a process upset or emergency (40 CFR 

§§60.100, et seq. (subpart J)).

On July 22, 2005, EPA, Our Children’s Earth Foundation 

and the Sierra Club fi led a proposed consent decree 

requiring EPA to review the NSPS for SO2 and PM and to 

fi nalize any revisions, if needed, within 30 months (EPA, 

2005c). The NSPS for petroleum refi neries have not been 

updated since 1974.

Power boilers at refi neries, which are used to generate 

electricity and steam, are subject to the NSPS for industrial 

boilers (40 CFR §§60.40b, et seq. (subpart Db); and 40 

CFR §§60.40c, et seq. (subpart Dc)) discussed in Chapter 

6, Industrial and Commercial Boilers. Newer boilers are 

subject to limits for PM, SO2, and NOx emissions under 

these rules.

Table 11.5

NSPS for Petroleum Refi neries (40 CFR §§60.100, et seq., (subpart J))a

Source Applicable Date Controls PM Opacity SO2

b

Fluid catalytic 

cracking 

unit catalyst 

regenerator 

After June 11, 1973 With or without 

controls

2.0 lb/ton of 

coke burn-offc

30%d NA

With control device NA NA 90% reduction or 50 ppm, 

whichever is less stringent

Without control 

device

NA NA 20 lb/ton of coke burn-offe

Claus sulfur 

recovery plant

After October 4, 1976 Reduction or 

oxidation control 

system followed by 

incineration

NA NA 250 ppmf

Reduction control 

system not followed 

by incineration

NA NA 300 ppmg,h

a. Any fl uid catalytic cracking unit in which a contact material reacts with petroleum derivatives to improve feedstock quality and in which 

the contact material is regenerated by burning off coke and/or other deposits, and that commenced construction, reconstruction or 

modifi cation on or before January 17, 1984 is exempt from these standards.

b. Any fl uid catalytic cracking unit catalyst regenerator that commenced construction, reconstruction or modifi cation on or before January 

17, 1984 is exempted from the SO2 standards.

c. In addition, if the gases discharged by the unit pass through an incinerator or waste heat boiler in which auxiliary or supplemental fossil 

fuel is burned, PM emissions may not exceed 0.10 lb/MMBtu of heat input attributable to such fossil fuel.

d. Exception: opacity may exceed 30% for one 6-minute average during any 1-hour period.

e. Another option is to use fresh feed (any petroleum derivative feedstock stream charged directly into the riser or reactor of a fl uid 

catalytic cracking unit, except for petroleum derivatives recycled within the unit, fractionator or gas recovery unit) in the fl uid catalytic 

cracking unit that has a total sulfur content no greater than 0.30% by weight.

f. At 0% excess air.

g. Additional limit of 10 ppm hydrogen sulfi de.

h. The emissions limit is 300 ppmv of reduced sulfur compounds, calculated as ppmv SO2 (dry basis) at 0% excess air.
166 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Regional Haze/Best Available Retrofi t 

Technology

Under the regional haze program, Best Available Retrofi t 

Technology (BART) requirements apply to emissions 

of PM2.5 and PM2.5-precursors from large sources that 

fall into 26 identifi ed source categories and that began 

operation between 1962 and 1997, in both attainment and 

nonattainment areas. Petroleum refi neries are among the 

identifi ed source categories. However, states have not yet 

developed their BART rules.

New Source Review/Prevention of Signifi cant 

Deterioration

New Source Review (NSR) and Prevention of Signifi cant 

Deterioration (PSD) requirements apply to new and 

modifi ed large stationary sources in nonattainment and 

attainment areas, respectively. Under these programs, 

plants in nonattainment areas are subject to Lowest 

Achievable Emission Rate (LAER) standards, while plants 

in attainment areas are subject to Best Available Control 

Technology (BACT) standards. Neither BACT nor LAER 

standards are codifi ed, because they are intended to refl ect 

technology advancements as they occur.

The Arizona Department of Environmental Quality has 

recently issued an air permit for the proposed Arizona 

Clean Fuels refi nery (Arizona DEQ, 2005). The permit 

provides an example of the controls to be installed at a new 

refi nery:

The facility’s two steam boilers will be fi red with 

natural gas and will be equipped with low-NOx

burners and FGR.

The facility’s 18 process heaters will be equipped 

with low-NOx burners; nine will also be equipped 

with SCR controls.

Catalyst regenerators at the catalytic reforming unit 

will be equipped with a wet scrubber.

The permit prohibits the use of fl ares as pollution 

control devices for intermittent or routine, nonemergency hydrocarbon releases.

The permit prohibits the combustion of fuel oil in the 

refi nery’s boilers and heaters. Natural gas and fuel 

gases generated within the refi nery are the only fuels 

allowed.

The permit requires the refi nery to meet several 

equipment design standards and work practice 

requirements in order to minimize SO2 emissions 

during upsets and malfunctions of the sulfur recovery 

process.

•

•

•

•

•

•

Maximum Achievable Control Technology

MACT standards address emissions of HAPs from new 

and existing sources in identifi ed industry categories, 

in both attainment and nonattainment areas. MACT 

standards apply to sources with potential emissions of 

10 tons per year of a single HAP or 25 tons per year of 

combined HAPs. 

Petroleum refi neries are subject to the MACT standards at 

40 CFR §§63.1560, et seq. (subpart UUU); in particular, 

these standards address catalytic cracking units, catalytic 

reforming units and sulfur recovery units. Units are 

considered new if they commenced construction, 

reconstruction or modifi cation after September 11, 1998; 

all other units are considered existing.

The MACT standards regulate PM and SO2 as surrogates 

for HAPs.3 Specifi cally, PM is used as a surrogate for 

metal HAPs in catalytic cracking units and SO2 is used as 

a surrogate for sulfur HAP emissions from sulfur recovery 

units.

The MACT standards mandate the same PM limits as 

the NSPS for catalytic cracking units and sulfur recovery 

units subject to the NSPS (see description above). 

Catalytic cracking units not subject to the NSPS have four 

compliance options:

meet the NSPS standards for PM;

meet a PM limit of 2.0 pounds per ton (lb/ton) of 

coke burn-off;4

meet a nickel emissions limit of 13,000 milligrams 

per hour (0.029 pounds per hour (lb/hr)); or

meet a nickel emissions limit of 1.0 milligram per 

kilogram (0.002 lb/ton) of coke burn-off in the 

catalyst regenerator.

Sulfur recovery units not subject to the NSPS have two 

options: (1) meet the NSPS standards; or (2) meet a total 

reduced sulfur emissions limit of 300 ppmv of total 

reduced sulfur compounds, expressed as an equivalent SO2

concentration (dry basis) at 0 percent oxygen.

Power boilers and process heaters at refi neries are subject 

to the Industrial/Commercial/Institutional Boilers 

and Process Heaters National Emission Standards for 

Hazardous Air Pollutants (40 CFR 63 Subpart DDDDD), 

3. Note that 40 CFR §§63.640, et seq. (subpart CC) include additional 

HAP limits for petroleum refi neries that do not use PM or SO2 as surrogates.

4. While the limit of 2.0 lb/ton is the same as the NSPS, these units are 

not subject to the NSPS requirement if the gases discharged by the unit 

pass through an incinerator or waste heat boiler in which auxiliary or 

supplemental fossil fuel is burned; in that case, PM emissions may not 

exceed 0.10 lb/MMBtu of heat input attributable to such fossil fuel.

1.

2.

3.

4.
 Chapter 11 - Petroleum Refi neries 167

discussed in Chapter 6, Industrial and Commercial Boilers. 

Larger liquid-fueled boilers and process heaters are 

subject to PM, hydrogen chloride and CO limits. Larger 

gaseous-fueled units are subject to a CO limit. Different 

limits generally apply to new and existing units. A new or 

reconstructed unit is one that commenced construction or 

reconstruction on or later than January 13, 2003.

Petroleum Refi nery Enforcement Initiative

In addition to the regulatory requirements described above, 

EPA in 1998 initiated an enforcement program known as 

the Petroleum Refi nery Initiative to address alleged Clean 

Air Act violations at petroleum refi neries (EPA, 2005b). 

The program addresses four areas:

PSD/NSR;

NSPS;

Leak Detection and Repair (LDAR) requirements; 

and

Benzene National Emissions Standards for Hazardous 

Air Pollutants.

EPA has entered into consent decrees with 83 refi neries (17 

companies), comprising 77 percent of the nation’s refi nery 

capacity.5

 The consent decrees already lodged will reduce 

annual refi nery SO2 emissions by 237,000 tons per year 

and NOx emissions by 81,000 tons per year, as well as 

an undetermined amount of PM and other pollutants. 

Refi neries have agreed to spend over $4 billion on new 

control technologies, pay over $60 million in civil penalties 

and spend over $65 million in environmental projects in 25 

states (EPA, 2005b, 2005d).

We provide details on the ConocoPhillips consent decree 

as an example of the control measures that the government 

is requiring in its petroleum refi nery cases. In its January 

27, 2005 consent decree with EPA, ConocoPhillips 

agreed to make substantial reductions of PM, SO2 and 

NOx emissions. Specifi cally, the company must install 

an SCR system or a Scrubber-Based NOx Emission 

Reduction Technology (SNERT) on various units in order 

to achieve a NOx concentration of between 20 and 40 

ppmv (the actual limit depends on the type of unit) on a 

365-day rolling average basis; and 40 ppmv on a seven-day 

rolling average basis, at 0 percent oxygen. Other units are 

required to use NOx-reducing catalyst additives and lowNOx combustion promoters. Furthermore, combustion 

units other than internal engines must install SCR, SNCR, 

new ultra-low-NOx burners or other technologies that the 

company demonstrates will reduce NOx emissions to 0.040 

lb/MMBtu or lower. Internal combustion engines must 

install combustion controls to reduce NOx emissions by 

80 percent or more compared to an uncontrolled internal 

5. The consent decrees are available at www.epa.gov/compliance/resources/cases/civil/caa/oil/index.html.

•

•

•

•

combustion engine (U.S. v. ConocoPhillips, 2005).

For SO2 control, the agreement requires six fl uidized 

catalytic cracking units (FCCUs) to install wet gas 

scrubbers and meet an SO2 concentration limit of 25 ppmv 

or less on a 365-day average basis; and 50 ppmv or lower 

on a seven-day rolling average basis, at 0 percent oxygen. 

For PM control, fi ve FCCUs will install wet gas scrubbers 

to achieve an emissions limit of 1 lb/ton of coke burned on 

a three-hour average basis (U.S. v. ConocoPhillips, 2005).

Finally, the company must install continuous emissions 

monitoring systems to demonstrate compliance, and some 

facilities must also install continuous opacity monitoring 

systems (U.S. v. ConocoPhillips, 2005).

State and Local Policy Measures

As discussed in Chapter 4, The Clean Air Act, state and 

local authority varies with regard to the imposition of more 

stringent regulations than the Clean Air Act and federal 

regulations require. Some states and local agencies have 

no limitations in this regard, while the limitations in other 

states vary. For the purposes of this discussion, we will 

assume that SIP writers are familiar with applicable state 

and local laws and regulations. 

For states that can impose more stringent requirements 

than those promulgated under federal law, several options 

are available.

For example, the South Coast AQMD Rule 1105.1 limits 

PM106

 and ammonia emissions from fl uid catalytic cracking 

units at oil refi neries. Refi nery operators can comply 

with one of three PM10 emissions limits: 3.6 lb/hr, 0.005 

grain per dry standard cubic foot of fl ue gas corrected to 3 

percent oxygen dry, or 2.8 lb per thousand barrels of fresh 

feed. Oil refi neries are expected to implement several 

control technologies to meet the emissions limits, including 

ESPs, SOx reducing agents and wet gas scrubbers. The 

South Coast AQMD is also developing a rule to limit SO2

emissions from fl aring operations. The rule builds on a 

pre-existing requirement (Rule 1118) that required eight 

refi neries and two other facilities to collect emissions 

data from their vent gas fl aring operations (South Coast 

AQMD, 2004a).

The Bay Area AQMD adopted a rule on July 20, 2005 

limiting emissions from fl aring operations. The rule 

builds on a June 2003 rule requiring refi neries to monitor 

and report fl are emissions data. It requires that each 

refi nery prepare a Flare Minimization Plan that determines 

how best to minimize fl aring. The Bay Area AQMD must 

6. The South Coast rule explicitly limits fi lterable PM10 emissions. 

Filterable PM consists of directly emitted particles captured on the fi lter 

of a stack test train and can include PM2.5.
168 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

approve the plans, which must be updated annually to 

incorporate the latest technologies and practices (Bay Area 

AQMD, 2005a). 

The Bay Area AQMD also adopted a rule (Rule 9-10) on 

July 1, 1997 requiring refi neries to limit NOx emissions 

from boilers, steam generators and process heaters to a 

refi nery-wide NOx standard of 0.033 lb/MMBtu. Smaller 

units are exempt from the rule (Bay Area AQMD, 2002b). 

Seebold provides a case study of how one San Francisco 

Bay refi nery achieved the standard (2001). With the 

application of new burner technology, the facility was able 

to reduce NOx emissions from its process heater to less 

than 20 ppm. No back-end controls were required. Also, 

the facility was able to reduce NOx emissions from its 

power boilers to less than 25 ppm without the use of backend controls.

Although VOCs have not been the focus of this discussion, 

the Bay Area AQMD has also adopted a stringent rule 

(Rule 8-18) to control VOC emissions from refi nery valves, 

fl anges, pumps, compressors, pressure relief valves, pipes, 

connections and other refi nery components. The rule 

was initially developed in 1980, strengthened signifi cantly 

in 1992, and amended at various points thereafter, most 

recently in 2004. The 2004 version of the rule requires that 

refi neries develop an LDAR program to locate, minimize 

and repair leaks from this equipment. The rule has the 

most stringent leak requirements in California (and the 

nation), and has signifi cantly reduced fugitive emissions 

from the area’s refi nery facilities (Bay Area AQMD, 

2004). 

State permitting authorities may also fi nd it useful in 

the context of permitting determinations to consider the 

emissions limits and control options required by the many 

petroleum sector settlement agreements. For example, 

several of the agreements require SCR controls on fl uid 

catalytic cracking units.

In general, fl exible compliance mechanisms for facilities 

like refi neries can signifi cantly reduce compliance costs, 

allowing better use of limited resources. Refi neries 

are complex operations with many different kinds of 

emissions sources. Boilers and process heaters, for 

example, will vary in terms of their age, size, capacity, 

utilization and space limitations. No single control 

technology or combination of controls will be appropriate 

in all situations. Recognizing this, the Houston-Galveston 

region established a NOx cap-and-trade program in 2000 

that included the region’s refi neries (TCEQ, 2000, 2002). 

In response to the fl exibility afforded by the cap-andtrade approach, refi nery operators implemented a wide 

range of strategies aimed at reducing NOx emissions. 

This included the retrofi t of large gas turbines with SCR 

systems, the decommissioning of smaller, lower effi ciency 

steam boilers, and the conversion of generating units to 

CHP systems (Deason, 2005). This diverse group of 

control strategies also appears in the agreements that the 

Texas Commission on Environmental Quality negotiated 

with several refi neries in the Beaumont/Port Arthur 

ozone nonattainment area. The agreements require the 

installation of scrubbers, the replacement of burners and 

the shut down of certain boilers (TCEQ 2004a, 2004b, 

2004c).

References

Arizona Department of Environmental Quality (DEQ). 

Air Quality Class I Permit for the Arizona Clean Fuels 

Refi nery, April 14, 2005. www.arizonacleanfuels.com/

letters/041405_Final_Issue_Permit.pdf.

Bay Area Air Quality Management District (AQMD). 

Environmental Impact Report (Draft): Alternative 

Compliance Plan To Use Interchangeable Emission 

Reduction Credits To Comply with the NOx Emission 

Limits of BAAQMD Rule 9-10; Valero Refi ning Company, 

California, June 2002. www.baaqmd.gov/pmt/public_

notices/2002/B2626/DRAFTEIR.htm. (2002a)

Bay Area Air Quality Management District (AQMD). 

“Regulation 9: Inorganic Gaseous Pollutants; Rule 10: 

Nitrogen Oxides and Carbon Monoxide from Boilers, 

Steam Generators and Process Heaters in Petroleum 

Refi neries,” Bay Area AQMD Rules & Regulations, July 

17, 2002. www.baaqmd.gov/dst/regulations/rg0910.pdf. 

(2002b)

Bay Area Air Quality Management District (AQMD). 

“Regulation 8: Organic Compounds; Rule 18: Equipment 

Leaks,” Bay Area AQMD Rules & Regulations, September 

15, 2004. www.baaqmd.gov/dst/regulations/rg0818.pdf.

Bay Area Air Quality Management District (AQMD). “Air 

District Board Adopts Refi nery Flare Rule,” Bay Area 

AQMD Press Release, July 20, 2005. www.baaqmd.gov/

pio/news/2005/fl are_050720.pdf. (2005a)

Bay Area Air Quality Management District (AQMD). Bay 

Area 2005 Ozone Strategy Volume 1 (Draft), September 

2005. www.baaqmd.gov/pln/plans/ozone/2005_strategy/

draft_vol1.pdf. (2005b) 

California Energy Commission and Electric Power 

Research Institute. Benefi ts of Advanced Distillation 

for Petroleum Refi ning and Chemical Production in 

California, February 2002.

California Environmental Protection Agency, Air 

Resources Board (CARB). Proposed List of Measures 

to Reduce Particulate Matter—PM10 and PM2.5

(Implementation of Senate Bill 656, 2003), November 18, 
 Chapter 11 - Petroleum Refi neries 169

2004.

Davis, W., Air & Waste Management Association. Air 

Pollution Engineering Manual: Second Edition, 2000.

Deason, D., ExxonMobil. Personal communication with 

M.J. Bradley & Associates, September 2005.

Eagleson, S.T., N. Confuorto, E.H. Weaver, S. Singhania, 

and N. Singhania. “A Logical and Cost-Effective Approach 

for Reducing Refi nery FCCU Emissions,” PETROTECH2005, Sixth International Petroleum Conference & 

Exhibition, January 16-19, 2005.

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environmentaldefense.org/article.cfm?ContentID=1537.

European Commission (EC). Integrated Pollution 

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Available Techniques for Mineral Oil and Gas Refi neries,

February 2003. http://www.bvt.umweltbundesamt.de/

archiv-e/esrefi neries-e.pdf.

Seebold, J.G., R.T. Waibel, and T.L. Webster. “Control 

Refi nery NOx Emissions Cost-Effectively,” Hydrocarbon 

Processing, November 2001. www.johnzink.com/whats_

new/pdfs/hydro_proc_11_2001.pdf.

Sexton, J., N. Confuorto, M. Barrasso, and N. Suchak. 

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Ashland Petroleum LLC’s Refi nery in Texas City, Texas,” 

NPRA Annual Meeting, March 23-25, 2004.

South Coast Air Quality Management District (AQMD). 

Final 2003 Air Quality Management Plan Appendix 

IV-A: District’s Stationary and Mobile Source Control 

Measures, August 2003. www.aqmd.gov/aqmp/docs/

2003AQMP_AppIVa.pdf.

South Coast Air Quality Management District (AQMD). 

AQMD Adopts Regulation To Reduce Particulate 

Emissions from Oil Refi neries, November 7, 2003. www.

aqmd.gov/news1/2003/bs11_07_03.htm.

South Coast Air Quality Management District (AQMD). 

AQMD To Seek Emission Reductions from Refi nery Flares,

September 3, 2004. www.aqmd.gov/news1/2004/bs9_03_

04.html. (2004a)

South Coast Air Quality Management District (AQMD). 

Final Environmental Assessment for: Proposed Amended 

Regulation XX—Regional Clean Air Incentives Market 

(RECLAIM), December 2004. www.aqmd.gov/ceqa/

documents/2005/aqmd/finalEA/FEA_RegXX.doc. 

(2004b)

South Coast Air Quality Management District (AQMD). 

“AQMD Adopts Regulations To Reduce Particulate 

Emissions from Oil Refi neries,” AQMD Advisor 11(1), 

January 2004. www.aqmd.gov/pubinfo/Publications/

Advisor/2004/AdvisorJan04.pdf. (2004c)

South Coast Air Quality Management District (AQMD). 

Refi nery Pilot Project Working Group, accessed September 

15, 2005, from: www.aqmd.gov/prdas/refi nery/index.html. 

(2005a)

South Coast Air Quality Management District (AQMD). 

REgional CLean Air Incentives Market (RECLAIM), 

accessed September 15, 2005, from: www.aqmd.gov/

reclaim/reclaim.html. (2005b)

Sunoco, Inc. Marcus Hook Refi nery To Build Sulfur Plant, 

accessed December 13, 2005, from: www.sunocoinc.

com/health_env_safety/ceresreport2002/hesgovernance_

projects.asp. 

Texas Commision on Environmental Quality (TCEQ) 

(formerly Texas Natural Resource Conservation 

Commission). Revisions to the State Implementation Plan 

for the Control of Ozone Air Pollution Post-1999 Rate-ofProgress and Attainment Demonstration for the Houston/

Galveston Ozone Nonattainment Area, December 6, 2000. 

www.tceq.state.tx.us/assets/public/implementation/air/sip/

sipdocs/2000-12-HGB/00011sip_ado.pdf.

Texas Commision on Environmental Quality (TCEQ) 

(formerly Texas Natural Resource Conservation 

Commission). Emissions Bank and Trade, November 25, 

2002. www.tceq.state.tx.us/permitting/air/nav/air_banking.

html.

Texas Commission on Environmental Quality (TCEQ). 

Agreed Order in the Matter of ExxonMobil Oil 

Corporation (Docket No. 2004-079-SIP), December 15, 

2004. www.tceq.state.tx.us/assets/public/implementation/

air/sip/agreements/2004-0846-SIP.pdf. (2004a)

Texas Commission on Environmental Quality (TCEQ). 

Agreed Order in the Matter of Huntsman Petrochemical 

Corporation (Docket No. 2004-0845-SIP), December 15, 

2004. www.tceq.state.tx.us/assets/public/implementation/

air/sip/agreements/2004-0845-SIP.pdf. (2004b)

Texas Commission on Environmental Quality (TCEQ). 

Agreed Order in the Matter of Premcor Refi ning Group, 

Inc. (Docket No. 2004-083-SIP), December 15, 2004. 

www.tceq.state.tx.us/assets/public/implementation/air/sip/

agreements/2004-0844-SIP.pdf. (2004c)

U.S. Department of Energy, Energy Information 

Administration (EIA). The Impact of Environmental 
170 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Compliance Costs on U.S. Refi ning Profi tability: Key 

Findings, October 29, 1997. www.eia.doe.gov/emeu/

perfpro/ref_pi/keyfi nd.html.

U.S. Department of Energy, Energy Information 

Administration (EIA). Petroleum Chronology of 

Events, 1970-2000, May 2002. www.eia.doe.gov/pub/

oil_gas/petroleum/analysis_publications/chronology/

petroleumchronology2000.htm.

U.S. Department of Energy, Energy Information 

Administration (EIA). Petroleum Products, March 2003. 

www.eia.doe.gov/neic/infosheets/petroleumproducts.htm.

U.S. Department of Energy, Energy Information 

Administration (EIA). Petroleum Supply Annual 2004, 

Volume 1, June 24, 2005. www.eia.doe.gov/oil_gas/

petroleum/data_publications/petroleum_supply_annual/

psa_volume1/psa_volume1.html. (2005a)

U.S. Department of Energy, Energy Information 

Administration (EIA). Petroleum Industry Analysis Brief, 

accessed September 15, 2005, from: www.eia.doe.gov/

emeu/mecs/iab98/petroleum/. (2005b)

U.S. Department of Energy (DOE). Technology Roadmap 

for the Petroleum Industry, February 2000. www.

eere.energy.gov/industry/petroleum_refining/pdfs/

petroleumroadmap.pdf.

U.S. Department of Energy (DOE). Steam System 

Opportunity Assessment for the Pulp and Paper, Chemical 

Manufacturing, and Petroleum Refi ning Industries,

October 2002.

U.S. Department of Labor Occupational Safety and 

Health Administration. “Section IV, Chapter 2: Petroleum 

Refi ning Processes,” in: OSHA Technical Manual, January 

20, 1999. www.osha.gov/dts/osta/otm/otm_iv/otm_iv_

2.html.

U.S. Environmental Protection Agency (EPA). Alternative 

Control Techniques Document: NOx Emissions from 

Process Heaters (Revised) (EPA-453/R-93-034), September 

1993. www.epa.gov/ttn/catc/dir1/procheat.pdf. (1993a)

U.S. Environmental Protection Agency (EPA). “Chapter 

8.13: Sulfur Recovery,” AP-42, Fifth Edition, Volume I, 

1993. www.epa.gov/ttn/chief/ap42/index.html. (1993b)

U.S. Environmental Protection Agency (EPA). “Profi le of 

the Petroleum Refi ning Industry,” Offi ce of Enforcement 

and Compliance Assurance Sector Notebook Project, 

September 1995. www.epa.gov/Compliance/resources/

publications/assistance/sectors/notebooks/petrefsn.pdf. 

(1995a) 

U.S. Environmental Protection Agency (EPA). “Chapter 

5.1: Petroleum Refi ning,” AP-42, Fifth Edition, Volume 

I, 1995. www.epa.gov/ttn/chief/ap42/ch05/index.html. 

(1995b)

U.S. Environmental Protection Agency (EPA). Regulation 

XX—Regional Clean Air Incentives Market (RECLAIM), 

May 12, 1998. http://yosemite.epa.gov/aa/programs.nsf/0/

fc33052905937dd88525651c00506e40?OpenDocument. 

U.S. Environmental Protection Agency (EPA). “Frequent, 

Routine Flaring May Cause Excessive, Uncontrolled Sulfur 

Dioxide Releases,” Enforcement Alert 3(9): 1-4, October 

2000. www.epa.gov/compliance/resources/newsletters/

civil/enfalert/fl aring.pdf. (2000a)

U.S. Environmental Protection Agency (EPA). “Standards 

of Performance for New Stationary Sources; Standards of 

Performance for Petroleum Refi neries,” 40 CFR §§60.100, 

October 17, 2000.

U.S. Environmental Protection Agency (EPA). Region 9: 

Cross-Program Activities: Regional Clean Air Incentives 

Market (RECLAIM), accessed August 15, 2005, from: 

www.epa.gov/region09/cross_pr/innovations/reclaim.html. 

(2005a)

U.S. Environmental Protection Agency (EPA). 

EPA Enforcement: National Petroleum Refi nery 

Initiative (Draft), August 24, 2005. www.epa.gov/

compliance/resources/cases/civil/caa/refineryinitiativepowerpoint082405.pdf. (2005b)

U.S. Environmental Protection Agency (EPA). “Proposed 

Settlement Agreement, Clean Air Act Citizen Suit; 

Proposed Consent Decree,” Federal Register 70(166): 

51040, August 29, 2005. (2005c)

U.S. Environmental Protection Agency (EPA). “U.S. 

Announces Clean Air Agreement with ExxonMobil: 

Nearly 77 Percent of Domestic Refi ning Capacity 

Now under Consent Decrees,” EPA Press Release, 

October 11, 2005. http://yosemite.epa.gov/opa/

admpress.nsf/d9bf8d9315e942578525701c005e573c/

4433b66d2e19b3d785257097005e8615!OpenDocument. 

(2005d)

U.S. Environmental Protection Agency (EPA). 1999 

National Emissions Inventory Final Version 3.0, obtained 

from EPA staff, October 2005. www.epa.gov/ttn/chief/net/

1999inventory.html. (2005e)

U.S., et al. v. Valero Refi ning Company and Tesoro 

Refi ning and Marketing Corporation (W.D. TX 2005), 

June 16, 2005. www.epa.gov/compliance/resources/

decrees/civil/caa/valero-cd.pdf.
 Chapter 11 - Petroleum Refi neries 171

U.S., et al. v. ConocoPhillips Company, No. H-05-

0258 (S.D. TX 2005), January 27, 2005. www.epa.gov/

Compliance/resources/decrees/civil/caa/conocophillipscd.pdf.

U.S., et al. v. ExxonMobil Company (N.D. IL 2005), 

October 11, 2005. www.epa.gov/compliance/resources/

decrees/civil/caa/exxonmobil-cd.pdf.

U.S., et al. v. Sunoco, Inc. (E.D. PA 2005), June 16, 2005. 

www.epa.gov/compliance/resources/decrees/civil/caa/

sunoco-cd.pdf.
172 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Diesel engine technology has changed dramatically in the 

last 20 years. EPA regulations have reduced the nitrogen 

oxides (NOx) and fi ne particulate matter (PM2.5) emissions 

from new onroad diesel truck and bus engines by 80 

percent1 and 90 percent, respectively, since 1988. 

To meet increasingly stringent emissions standards, engine 

manufacturers have made fundamental changes to engines 

and added exhaust “after-treatment” devices. Stricter 

standards that take effect between 2007 and 2010 will 

reduce allowable NOx and PM2.5 emissions by a further 90 

percent and are driving additional changes—primarily the 

use of even more effective after-treatment technologies.

Regulations for the diesel engines used in nonroad 

equipment such as ships, trains and agricultural and 

construction tractors have lagged—emissions standards 

for these engines will not achieve regulatory parity with 

those for onroad engines until 2015 or later. However, 

because many of these engines are very similar to onroad 

engines, the same technologies being developed for the 

onroad market can be used in many cases to reduce their 

emissions in advance of regulatory mandates.

While great progress has been achieved in reducing 

1. Due to the effect of engine “defeat devices,” actual NOx reductions 

for long-haul Class 8 onroad trucks have been less than what would be 

implied by the change in standards for engines built prior to 2002 (see 

Chapter 13, Diesel Trucks and Buses).

emissions from new diesel engines, there is a signifi cant 

legacy fl eet of older diesel engines still in use. Many of 

these engines were made before diesel emissions standards 

went into effect. Diesel trucks and buses can stay in 

service for 20 years, while some nonroad equipment can 

last for more than 40 years.

There are fi ve ways that exhaust emissions from existing 

diesel vehicle fl eets can be reduced—most of which 

take advantage of the progress that has been made in the 

development of new diesel engines. These approaches 

include: 

Replace or Repower: Retire vehicles or engines 

“early” and replace with new, cleaner engines. 

Retrofi t: Add an “after-treatment” device to the tail 

pipe and/or modify an existing engine to make it 

•

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Chapter 12

Diesel Engine Technologies
 Chapter 12 - Diesel Engine Technologies 173

cleaner.

Repair/Rebuild: Perform proper maintenance to 

ensure that all engines are as clean as possible given 

their technology level. 

Reduce Idling: Reduce unproductive engine idling, 

thereby reducing emissions and saving fuel.

Refuel: Use a “cleaner” alternative diesel fuel.

This chapter will discuss each of these approaches. For 

retrofi ts, alternative diesel fuels and idle reduction, we have 

included a brief description of the technologies that can 

be used, their costs, implementation issues and emissions 

benefi ts. 

The information presented here merits its own chapter 

because it is relevant to the emissions reduction strategies 

discussed in several other chapters, all of which rely on the 

application of technology to reduce emissions from in-use 

diesel engines. 

Engine/Vehicle Retirement

For many fl eets of older diesel vehicles, particularly those 

built prior to 1988, dramatic reductions in both PM2.5 and 

NOx emissions can be achieved by retiring older vehicles 

and replacing them with new vehicles equipped with new 

engines that meet much stricter emissions standards. In 

many cases, these new engines will also achieve better fuel 

economy, providing some economic benefi t to the owner. 

Another approach is to keep the vehicle but retire the 

engine—by repowering with a new engine. While some 

fl eet operators have taken this approach with onroad 

vehicles,2 it is much more likely to be cost-effective 

for nonroad fl eets, including some marine vessels, 

locomotives, and large specialty construction equipment. 

This type of equipment typically has a much longer 

lifespan than onroad trucks and buses; in addition, the 

engine generally represents a smaller percentage of the 

value of the entire vehicle. 

For some nonroad equipment, it may be possible to 

repower with an onroad engine certifi ed to lower emissions 

standards than new nonroad engines and thereby produce 

even greater emissions reductions (see Chapter 14, 

Nonroad Equipment). 

Engine Modifi cations

Some of the changes that have been made to onroad diesel 

engines over the last 20 years include the change from a 

two-stroke to four-stroke cycle, improved cylinder designs, 

2. Between 2000 and 2001, MTA New York City Transit repowered 600 

model year 1990 and 1993 urban transit buses with new engines.

•

•

•

improved fuel injectors and higher injection pressures, 

electronic fuel control, the addition of turbochargers, and 

the addition of exhaust gas recirculation. These changes 

have contributed to both improved fuel economy and lower 

emissions. To a lesser extent, these technology advances 

have also been applied to nonroad engines. 

Diesel engines, particularly the very large nonroad engines 

used in marine vessels, locomotives and some construction 

equipment, typically go through one or two major 

overhauls during their lifetime. Some of the changes that 

have been applied to new engine designs can be applied 

as an upgrade to existing engines during an overhaul, 

resulting in lower emissions. As with repowering, this 

approach is generally more practical and cost-effective for 

the largest and longest-lived nonroad engines. 

In general, diesel engine design involves a fundamental 

trade-off between NOx and PM formation in the cylinder. 

Relatively simple changes to the fuel injection timing of 

existing diesel engines can reduce NOx emissions by 20–

40 percent, but at the expense of an unacceptable increase 

in PM emissions. At least one manufacturer has taken the 

approach of combining engine timing changes with retrofi t 

of a diesel oxidation catalyst or diesel particulate fi lter to 

achieve simultaneous PM2.5 and NOx reductions. 

Repair/Rebuild

Engines that are properly maintained and tuned perform 

better and typically emit less pollution than poorly 

maintained engines, regardless of how old they are. Proper 

maintenance includes the periodic overhaul or rebuilding 

of the entire engine to evaluate and replace as necessary 

major components that can wear out, such as cylinder 

liners. Proper maintenance and rebuilding of severely 

worn engines may also increase fuel economy and extend 

engine life.

Any maintenance problem that restricts air fl ow into the 

engine or results in over-fueling is likely to increase PM 

emissions from a diesel engine. Increased emissions 

can result from something as simple as a dirty air fi lter. 

Other maintenance problems that can increase emissions 

include clogged or worn fuel injectors, worn fuel injection 

pumps, a malfunctioning turbocharger, worn cylinder 

liners, improper engine timing and leaks in the air intake 

manifold.

Retrofi t Technologies

“After-treatment” refers to a device or technology installed 

in a vehicle’s exhaust system to reduce emissions. Unlike 

in-engine and fuel technologies, these devices do not 

reduce the emissions produced by the engine; rather, they 

act to cleanse the exhaust after it has left the engine, but 
174 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Table 12.1

Emissions Reduction Potential (% reduction)

Technology NOx HC & CO PM2.5 Notes

Diesel oxidation 

catalyst (DOC)

no reduction 20%–50% 10%–30% PM2.5 reductions are primarily the “wet” liquid 

HC portion of PM2.5.

Passive diesel 

particulate fi lter 

(DPF) 

no reduction 60%–90% 80%–90%+ PM2.5 reductions of both HC and solid carbon 

particles. While DPFs do not affect the total 

mass of NOx emissions, they usually increase 

the ratio of NO2 to NO directly emitted, from 

less than 10%-30% or more.

Active diesel 

particulate fi lter 

(ADPF)

no reduction 60%–93% 80%–90%+ PM2.5 reductions of both HC and solid carbon 

particles. While DPFs do not affect the total 

mass of NOx emissions, they usually increase 

the ratio of NO2 to NO directly emitted, from 

less than 10%-30% or more.

Flow through fi lter 

(FTF)

no reduction 50%–89% 50%–76% Eliminates more PM2.5 carbon particles than a 

typical DOC.

Closed crankcase 

fi lter system 

(CCFS)

no reduction no reduction 5%–10% Additional PM reduction when combined with 

other PM after-treatment devices.

Exhaust gas 

recirculation (EGR)

30%–40% no reduction no reduction NOx reduction for both low- and high-pressure 

systems. EGR can achieve an 80% reduction 

in HC, CO and PM2.5 when combined with a 

DPF.

Selective catalytic 

reduction (SCR)

60% no reduction no reduction SCR can achieve a 25% reduction in HC, CO 

and PM2.5 when combined with a DOC; higher 

reductions are possible when combined with 

a DPF.

NOx reducing 

catalyst (NRC)

20%–30% no reduction no reduction NRC can achieve a 25% reduction in HC, CO 

and PM2.5 when combined with a DOC; higher 

reductions are possible when combined with 

a DPF.

NOx adsorber 90%+ 10%–90% 10%–90%

Emulsifi ed diesel 

(ED) fuel

5%–30% increase

(up to 35%)

20%–50%

Biodiesel increase

(up to 10%)

0%–50% 0%–50%

Oxygenated diesel 

(OD)

increase

(0%–10%)

0%–50% 0%–50% Ethanol is a renewable fuel that results in net 

fuel-cycle CO2 reductions.

Fuel-borne 

catalysts

0%–10% 0%–50% 0%–50%

Notes: For all technologies, the reported range of emissions reductions is from emissions test results under the EPA and California Air 

Resources Board (CARB) technology verifi cation programs.
 Chapter 12 - Diesel Engine Technologies 175

Typical Diesel Oxidation Catalyst 

Courtesy of Johnson Matthey, Inc. 

before it enters the atmosphere. With some exceptions 

and limitations, as noted below, after-treatment devices 

can be retrofi t onto existing diesel vehicles to reduce their 

emissions.

There are a number of different approaches to diesel 

exhaust after-treatment, but most include a catalyst that 

promotes chemical reactions in the exhaust, oxidizing the 

hydrocarbons (HC) and PM2.5 to carbon dioxide (CO2) and 

water, or reducing NOx to elemental nitrogen. In general, 

any after-treatment technology can either oxidize PM2.5

or reduce NOx, but not both at the same time. Different 

technologies can be combined in a single commercially 

available product, however, resulting in both lower PM2.5

and lower NOx emissions simultaneously. The nine most 

common diesel retrofi t technologies are described in detail 

below; they include both PM oxidation technologies and 

NOx reduction technologies. These technologies are all 

potentially applicable to a wide variety of diesel engines. 

Some are commercially available now for a signifi cant 

number of applications, others for a smaller number of 

specifi c engines. 

PM2.5 Technologies

Diesel Oxidation Catalyst. A diesel oxidation catalyst 

(DOC) is a fl ow-through metal or ceramic substrate 

coated with a precious metal catalyst (e.g., platinum) and 

packaged into a metal container similar to an exhaust 

muffl er/resonator. The DOC sits in the exhaust stream of 

a vehicle and promotes the oxidation of unburned PM, HC 

and carbon monoxide (CO) in the exhaust passing through 

it, producing CO2 and water.

The following implementation issues3 and costs4 apply 

when installing and operating DOCs:

If properly sized, DOCs can be used on virtually 

any diesel engine, with an appropriate catalyst 

formulation.

DOCs may not be appropriate for very old two-stroke 

engines with high oil consumption, as excess PM can 

plug the fl ow channels in the DOC. 

Retrofi t installation is generally straightforward and 

takes only a few hours.

Fuel should not have more than 500 parts per million 

(ppm) sulfur. With higher sulfur fuels, excessive 

sulfate PM2.5 is created across the catalyst.

3. For all technologies, information on implementation issues is taken 

from technology summaries on the EPA/OTAQ website, discussions 

with manufacturers and the author’s project experience.

4. Typical costs for all technologies are from technology summaries 

available on the EPA/OTAQ website and from the Manufacturers of 

Emissions Controls Association (MECA) independent cost survey noted 

in the reference section.

•

•

•

•

Purchase cost is $1,000–$2,000 for a typical truck or 

bus engine.

Larger engines generally require larger, more 

expensive devices.

DOCs have minimal effect on fuel economy.

Passive Diesel Particulate Filter. A passive diesel 

particulate fi lter (DPF) combines a DOC with a porous 

ceramic, metal mesh or silicon carbide fi lter in a metal 

container similar to an exhaust muffl er/resonator. There 

are several variations on the design: some DPFs have a 

separate fl ow-through catalyst section in series with an uncatalyzed fi lter, while others use a fi lter with the catalyst 

applied directly to it. The DPF sits in the exhaust stream of 

the vehicle like a typical muffl er/resonator. 

Inside the device, the gaseous components of the exhaust 

pass through the porous walls of the fi lter, while the solid 

PM2.5 particles are physically trapped on and in the fi lter 

walls. Carbon will typically oxidize only at temperatures 

greater than 600 degrees Centigrade (oC); the catalyst 

promotes oxidation of the trapped PM2.5 (carbon and 

•

•

•

CRTTM Diesel Particulate Filter

Courtesy of Johnson Matthey, Inc. 
176 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

hydrocarbons) at the temperatures more typical of diesel 

exhaust (200–400oC), which then exits the fi lter as gaseous 

CO2 and H2O. The catalyst also oxidizes gaseous HC and 

CO in the exhaust like a typical DOC. 

The following implementation issues and costs apply when 

installing and operating DPFs:

DPFs put a restriction in the exhaust and increase 

“back pressure” on the engine pistons; they must be 

carefully designed to minimize this impact, since 

high back pressure can lead to progressive engine 

damage. 

Non-combustible components of lube oil collect as 

ash in the fi lter over time. Approximately once per 

year, DPFs must be removed from the vehicle and 

cleaned to remove this collected ash. 

As ash or excess carbon builds up in the fi lter, engine 

back pressure rises. DPFs should always be used with 

a back-pressure monitoring system that triggers a 

maintenance light once the back pressure rises above 

a set threshold.

Fuel cannot have more than 50 ppm sulfur. Higher 

levels of sulfur reduce the oxidation effi ciency of 

collected PM2.5 and can result in fi lter plugging. As 

discussed in Chapters 13 and 14, onroad diesel fuel 

will be required to have less than 15 ppm sulfur 

beginning in late 2006. This ultra-low-sulfur fuel 

is available in some parts of the country today and 

can be used with DPFs. Nonroad diesel fuel with 

sulfur levels of 500 ppm or more will continue to 

be available through 2010. DPF retrofi ts will not be 

possible on nonroad equipment until after 2010 unless 

onroad fuel is used. 

DPFs will not work on all engines. The more PM the 

engine produces, the larger the fi lter and catalyst must 

be to work continuously without plugging. For some 

very old, very dirty engines it may not be practical to 

design a DPF that will work consistently, due to cost 

issues and space constraints. 

The DPF also requires a minimum exhaust 

temperature of 240–300o

C for 35–40 percent of 

the time to oxidize the collected PM2.5 in the fi lter. 

This is easily achievable for many vehicles, but 

certain engines and certain duty cycles may not 

have suffi cient exhaust temperature to use a DPF 

effectively. In general, DPFs can be used for duty 

cycles in which the diesel engine operates for a 

majority of the time under high loads. Lightly 

loaded duty cycles may not be appropriate for DPFs. 

Evaluation of the temperature profi le for the engine/

duty cycle is highly recommended before retrofi tting 

DPFs on a vehicle type for the fi rst time.

Installation is relatively straightforward and usually 

•

•

•

•

•

•

•

takes less than fi ve hours per vehicle.

Purchase cost is $5,000–$10,000 for a typical truck 

or bus engine.

Larger engines generally require larger, more 

expensive devices.

DPFs have minimal effect on fuel economy.

Active Diesel Particulate Filter. An active diesel 

particulate fi lter (ADPF) system uses the same porous 

fi lter as a passive DPF to remove PM2.5 from diesel 

exhaust. Like a passive DPF, these systems may also 

employ a catalyst to lower the temperature at which the 

collected PM2.5 will oxidize out of the fi lter. However, in 

order to accommodate a wider range of duty cycles, they 

also incorporate some kind of active system to raise the 

temperature inside the fi lter. 

The most common method used to raise the temperature in 

the fi lter is to inject additional diesel fuel into the exhaust 

stream across a small catalyst, downstream of the engine 

but in front of the fi lter. Oxidation of this fuel raises the 

temperature. 

It is expected that virtually all new onroad diesel trucks 

and buses will use ADPF systems beginning in 2007 to 

comply with the stricter EPA PM standards that will take 

effect at that time. While there are currently very few 

ADPF systems commercially available for retrofi t, it is 

expected that more will become available after 2007.

The following implementation issues and costs apply when 

installing and operating ADPFs:

ADPFs increase back pressure on the engine 

pistons and must be carefully designed to minimize 

this impact, since high back pressure can lead to 

progressive engine damage. 

Non-combustible components of lube oil collect as 

ash in the fi lter over time. Approximately once per 

year, ADPFs must be removed from the vehicle and 

cleaned to remove this collected ash. 

ADPFs will work on a wider range of engines and 

duty cycles than passive DPFs because they are not 

limited by the inherent exhaust temperature profi le.

ADPF systems are signifi cantly more complicated 

than passive DPFs. In addition to the fi lter element, 

an active DPF system will typically contain a fuel 

pump, a fuel injector into the exhaust, a separate 

catalyst, back-pressure and temperature monitors and 

an Electronic Control Module (ECM).

Depending on whether or not a catalyst is used to 

help oxidize collected PM out of the fi lter, ADPF 

systems may be usable with fuel that has up to 

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•
 Chapter 12 - Diesel Engine Technologies 177

500 ppm sulfur. Fully active systems that raise 

the exhaust temperature above 600oC to oxidize 

collected carbon can operate on the higher sulfur 

fuels. However, systems that incorporate a catalyst 

will be limited to operation on fuel with less than 50 

ppm sulfur in the same way as DPFs. Most systems 

designed for use with onroad vehicles are expected 

to include a catalyst and will require the lower sulfur 

fuels that are due to become readily available for 

onroad vehicles beginning in late 2006.

Purchase cost for early retrofi t devices is expected to 

be comparable to current DPF prices: $5,000–$10,000 

for a typical truck or bus engine. As manufacturing 

volume increases to accommodate the installation 

of ADPFs on all new trucks after 2007, this price is 

expected to fall signifi cantly.

Larger engines generally require larger, more 

expensive devices.

ADPFs incur a fuel economy penalty of 4–7 percent 

for operation of the active system.

Flow Through Filter. A fl ow through fi lter (FTF) is very 

similar to a DOC, but it uses a different type of substrate 

to hold the catalyst material. Different manufacturers use 

wire mesh, wire fl eece or sintered metal, all coated with a 

precious metal catalyst and packaged into metal containers 

similar to those used to package a DOC.

As in a DOC, the catalyst promotes the oxidation of 

unburned carbon, HC and CO in the exhaust, producing 

CO2 and water. Because of the substrate formation, 

individual PM2.5 particles typically have greater 

opportunity to contact a catalyst site than in a typical DOC 

so that an FTF eliminates a greater percentage of PM2.5

than a typical DOC.

The following implementation issues and costs apply when 

installing and operating FTFs:

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Particulate ReactorTM Flow Through Filter

Courtesy of Fleetguard Emission Solutions 

FTFs, if properly sized and made with an appropriate 

catalyst formulation, can be used on a greater range 

of diesel engines than passive DPFs.

Like passive DPFs, FTFs require a minimum exhaust 

temperature to work consistently and therefore cannot 

be used in all duty cycles.

Retrofi t installation is generally straightforward and 

takes only a few hours.

Fuel should not have more than 500 ppm sulfur. With 

higher sulfur fuels, excessive sulfate PM2.5 is created 

across the catalyst.

Purchase cost is $3,000–$4,000 for a typical truck or 

bus engine.

Larger engines generally require larger, more 

expensive devices.

FTFs have minimal effect on fuel economy.

Closed Crankcase Filter System. Most current 

diesel engines have “open” crankcases, which are vented 

to the atmosphere to relieve any pressure that builds up as 

combustion gases leak from the cylinders into the crank 

case. While the fl ow from these vents is generally much 

smaller than exhaust fl ow from the tail pipe, crank case 

vent emissions include combustion gases, unburned fuel, 

various HC vapors, diesel PM and engine oil droplets. 

Under current EPA standards and test procedures, 

these crank case vent gases are not included in exhaust 

emissions limits. Nonetheless, they can be signifi cant. 

Testing conducted under the EPA Verifi cation Program 

(discussed below) on a 1998 onroad diesel engine showed 

that PM emissions from the crank case vent totaled 16–23 

percent of the PM emissions coming from the tail pipe 

(RTI, 2003). 

A closed crankcase system routes gases from the crankcase 

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Closed Crankcase Filter Installed on a Bus

Courtesy of Donaldson 

Company, Inc.
178 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

vent to the engine’s air intake manifold, effectively 

closing the crank case. These systems generally include a 

pressure-regulating valve and an oil fi lter to keep oil in the 

vent gases from fouling the engine’s turbocharger. 

The following implementation issues and costs apply when 

installing and operating a closed crankcase fi lter system:

Closed crankcase systems can be installed on 

virtually any diesel engine.

Retrofi t installation is generally straightforward and 

takes only a few hours.

Removing crankcase vent emissions generally results 

in a cleaner vehicle engine compartment.

Purchase cost is $250–$500 for a typical truck or bus 

engine.

Closed crankcase systems have no effect on fuel 

economy.

NOx Technologies

Exhaust Gas Recirculation. In an exhaust gas 

recirculation (EGR) system, some of the exhaust gas from 

the diesel engine is rerouted back to the engine’s air intake 

manifold to be mixed with the combustion air before it 

enters the cylinder. This introduces inert gas (CO2) into 

the cylinder that dilutes the air charge, absorbs heat and 

reduces peak combustion temperature in the engine, 

thus reducing the production of NOx during combustion. 

Technically, EGR is not an after-treatment technology 

because it fundamentally affects the engine’s combustion 

cycle and reduces engine emissions. 

Since 2003, most new onroad diesel engines have 

included high-pressure cooled EGR systems that redirect 

exhaust fl ow to the air intake using an electronically 

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controlled valve mounted just downstream of the engine 

turbocharger. Control of this exhaust valve in response 

to differing engine conditions is accomplished using the 

engine’s ECM. These types of systems could theoretically 

be retrofi t on electronically controlled engines. 

Low-pressure EGR systems are also available that can be 

retrofi t onto virtually any diesel engine. These systems 

typically redirect exhaust fl ow to the air intake using a 

valve mounted much further back in the exhaust stream, 

where the valve is controlled with an ECM separate 

from the engine ECM. These systems must be used in 

conjunction with a passive or active DPF, because the 

redirected air entering the air intake must have low levels 

of particulate.

The following implementation issues and costs apply when 

installing and operating an EGR system:

Both low- and high-pressure EGR systems add 

equipment to the engine that may be diffi cult to fi t in 

existing engine compartments and that may increase 

maintenance costs. 

Retrofi t of a high-pressure system may also require an 

upgrade to the existing engine cooling system, since 

the EGR cooler can add up to 40 percent additional 

heating load to the engine cooling loop.

High-pressure EGR systems force more PM into the 

engine oil, reducing effective oil life.

Low-pressure EGR systems require engine mapping 

to develop effective control algorithms.

EGR applied to a new engine adds a modest amount 

to the cost of the engine.

Retrofi ts can cost $10,000–$15,000, including the 

cost of the required DPF.

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SCRTTM SCR System

Courtesy of Johnson Matthey, Inc

Longview® Lean NOx Catalyst System

Courtesy of Cleaire and Fleetguard Emission Solutions
 Chapter 12 - Diesel Engine Technologies 179

EGR systems incur a fuel economy penalty of 2–4 

percent.

Selective Catalytic Reduction. Selective Catalytic 

Reduction (SCR) technology uses a reducing agent in 

conjunction with a special SCR catalyst to reduce the NOx

in diesel exhaust to elemental nitrogen. The SCR catalyst 

sits in the exhaust stream, much like a DOC or DPF, and 

the reductant is injected into the exhaust ahead of the 

catalyst, much like the diesel fuel in an active DPF system. 

The most common reductant used with SCR is a solution 

of urea in water, which is kept in a separate tank on the 

vehicle. Once injected, the urea becomes ammonia and 

a chemical reduction reaction between the ammonia 

and NOx takes place across the SCR catalyst. The urea 

injection is managed by an ECM that carefully matches 

the volume of injected urea to the engine’s exhaust fl ow. 

Since some ammonia can slip through the SCR catalyst, 

most SCR systems also include a DOC or DPF downstream 

from the SCR catalyst to clean up the ammonia. The DOC 

or DPF will also reduce PM emissions.

The following implementation issues and costs apply when 

installing and operating an SCR system:

SCR systems can be used on virtually any diesel 

engine.

SCR systems add signifi cant equipment to the engine 

system and increase ongoing maintenance costs. 

In addition to the SCR catalyst, an SCR system 

will typically require a urea tank, a urea pump and 

injector, back-pressure and temperature monitors and 

an ECM.

SCR requires the use of urea reductant. While urea 

is produced in plentiful quantities as an industrial 

chemical and is relatively inexpensive ($0.80/gallon), 

the retail urea distribution infrastructure in place 

in the U.S. is currently limited. Fleet operators can 

contract for urea delivery to their own centralized 

fueling locations, but vehicle operators currently 

have very limited ability to purchase urea at existing 

retail fuel outlets. 

SCR systems typically use approximately one gallon 

of urea for every 20 gallons of diesel fuel.

SCR systems require engine mapping and exhaust 

temperature measurement to develop effective 

control algorithms.

Fuel should have no more than 500 ppm sulfur 

for operation of the SCR system itself. If used in 

conjunction with a DPF, fuel sulfur cannot be more 

than 50 ppm, as noted above.

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An SCR system typically costs $10,000–$20,000 for 

a truck or bus engine.

As with the other retrofi t technologies described 

above, the cost of SCR systems generally increases 

with engine horsepower. 

SCR systems have minimal effect on fuel economy

NOx Reducing Catalyst. A NOx reducing catalyst 

(NRC) system works in the same way as an SCR system, 

but it uses diesel fuel as a reductant instead of a urea 

solution. The NRC catalyst sits in the exhaust stream 

much like a DOC or DPF and the diesel fuel reductant is 

injected into the exhaust ahead of the catalyst. HC from 

the injected fuel contribute to a chemical reduction reaction 

with the NOx in the exhaust, across the NRC catalyst. 

Since diesel fuel is not as effective a reductant as urea, 

NRC systems reduce less than half as much NOx as SCR 

systems.

Because of the potential for increased HC and CO 

emissions from the injected fuel, most NRC systems 

also include a DOC or DPF downstream from the NRC 

catalyst.

The following implementation issues and costs apply when 

installing and operating an NRC:

NRC systems can be used on virtually any diesel 

engine.

NRC systems add signifi cant equipment to the engine 

system and increase ongoing maintenance costs. In 

addition to the NRC catalyst, an NRC system will 

typically contain a fuel pump, a fuel injector, backpressure and temperature monitors (because exhaust 

temperature is critical in these applications) and an 

ECM.

Fuel should have no more than 500 ppm sulfur, 

though ultra-low-sulfur diesel with less than 15 ppm 

sulfur is preferable, if available.

Purchase cost of $6,500–$10,000 for a typical truck 

or bus engine.

As with the other retrofi t technologies described 

above, the cost of NRC systems generally increases 

with engine horsepower. 

NRC systems incur a fuel economy penalty of 4–7 

percent because of the fuel used as a reductant.

NOx Adsorber. Unlike SCR and NRC systems, 

which continually reduce NOx to elemental nitrogen by 

combining the oxygen in NOx with HC (diesel fuel or 

ammonia), the materials in a NOx adsorber chemically 

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180 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

combine with NOx under lean (high oxygen content) 

conditions typical of diesel engine exhaust. In this way, 

the NOx adsorber chemically collects nitrogen over time. 

Eventually, the nitrogen must be released in order to make 

room to collect more. This is done by creating rich (low 

oxygen, high HC) conditions in the exhaust. Since rich 

operation is not typical of diesel engine operation, this is 

done by injecting fuel into the exhaust (similar to an NRC 

system). 

NOx adsorbers are typically set up as a dual bed system 

with a series of dampers to minimize the fuel penalty. 

NOx adsorber technology is expected to take a leading role 

in complying with the more stringent EPA onroad NOx

standards that take effect between 2007 and 2010. EPA 

believes that NOx adsorbers are applicable to nonroad 

engines and that they will also be used to comply with the 

Tier 4 nonroad NOx standards that will take effect between 

2008 and 2015.

Due to the high level of engine integration necessary 

to make adsorber systems work, it is unclear at this time 

whether NOx adsorber technology will be available as a 

retrofi t option and if so, when.

The following implementation issues and costs apply when 

installing and operating a NOx adsorber system:

NOx adsorber systems can theoretically be used on 

virtually any diesel engine.

NOx adsorber systems add signifi cant equipment 

to the engine system, increasing on-going 

maintenance costs. In addition to the NOx adsorber 

beds themselves, a NOx adsorber system typically 

contains a fuel pump, a fuel injector, back-pressure 

and temperature monitors and an ECM. It may also 

contain dampers to control fl ow to multiple adsorber 

beds. 

The materials used in NOx adsorbers capture and 

store sulfur compounds that can be released only 

with a very high temperature cycle. For this reason, 

fuel with no more than 15 ppm sulfur must be used.

Costs are unknown at this time. In its regulatory 

impact analysis for the 2007 onroad diesel engine 

standards, EPA projected that NOx adsorbers would 

ultimately cost about 25 percent more than DPFs. In 

the short term, early retrofi t systems are expected to 

cost as much or more than current SCR systems.

NOx adsorbers incur a fuel economy penalty of 4–7 

percent because of the fuel used to release collected 

nitrogen from the adsorber catalyst.

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Alternative Diesel Fuels

Various fuel parameters can affect both NOx and PM2.5

emissions, regardless of both engine and after-treatment 

technology. One approach to reducing emissions is to use 

a non-standard diesel fuel formulation.

Most alternative “clean” diesel fuels are based on blending 

a small amount (up to 20 percent by volume) of another 

substance with commercially available petroleum diesel. 

Various approaches are available, including blending with 

water (emulsifi ed diesel), alcohol (oxy-diesel), converted 

vegetable oil (biodiesel) or metal-based powdered catalysts 

in a liquid suspension (fuel-borne catalysts). In the future, 

synthetic diesel fuel made from natural gas may also be 

available. 

In addition, reducing sulfur levels in diesel fuel can 

itself reduce PM emissions, while also improving the 

effectiveness of some retrofi t PM control devices, as 

discussed above. EPA rules will require signifi cant diesel 

sulfur reductions beginning in late 2006. In some parts of 

the country, ultra-low-sulfur diesel fuel with less than 30 

ppm sulfur has been available for several years, ahead of 

EPA mandates. Some fl eets have already begun to use this 

fuel in order to reduce emissions. 

The implementation dates for mandatory sulfur reductions 

in nonroad and marine fuels lag those for onroad fuel 

by several years. Between now and 2012, the use of 

reduced-sulfur onroad diesel fuel in nonroad construction, 

locomotive and marine engines could complement other 

emissions reduction strategies. See Chapters 13 (Trucks 

and Buses) and 14 (Nonroad Equipment) for a full 

discussion of this issue. 

Emulsifi ed Diesel Fuel. Emulsifi ed diesel fuel (ED) 

is commercial diesel fuel blended with up to 20 percent 

water and a small amount of a proprietary hydrocarbon 

additive. The additive creates a stable emulsion that will 

not separate, in which the water molecules are completely 

enclosed by fuel molecules. This prevents the water from 

coming into contact with the engine and fuel system 

components, thereby preventing corrosion and maintaining 

lubricity. 

During combustion, evaporation of the water contained 

in the fuel decreases peak combustion temperatures; 

this lowers NOx formation and also results in greater 

atomization of the fuel, which reduces PM2.5 emissions.

The following implementation issues and costs apply when 

using ED:

Emulsifi ed fuel can be used in virtually any diesel 

engine without modifi cation.

Creation of the emulsion requires specialized 

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 Chapter 12 - Diesel Engine Technologies 181

blending equipment. Blending can be done at the 

fuel supplier’s terminal or at a customer site.

Emulsifi ed fuel is stable, but it can stratify if left in a 

tank for an extended period without use.

Because of its water content, emulsifi ed fuel has 10–

30 percent lower effective energy content per gallon 

than standard diesel, resulting in lower fuel economy 

(miles per gallon). 

Since fuel is typically metered into an engine’s 

cylinder by volume, the use of emulsifi ed fuel will 

result in a 10–30 percent reduction in power output at 

the same throttle setting.

ED typically costs $0.01–$0.10 per gallon more than 

the base diesel fuel. In addition, typical vehicles will 

use 10–20 percent more fuel to do the same amount 

of work.

Biodiesel. Biodiesel (sometimes called BD) is a 

renewable fuel with high oxygen content and low sulfur 

content. It is composed of mono-alkyl esters and longchain fatty acids derived from vegetable oils or animal fat. 

Biodiesel has very similar properties to petroleum diesel. 

Oxygenates in biodiesel lower PM2.5 emissions by 

supplying additional combustion oxygen. This can also 

increase peak combustion temperature, resulting in 

additional NOx formation. 

The following implementation issues and costs apply when 

using biodiesel fuel:

Biodiesel can be used in virtually any diesel engine 

with no or minimal modifi cations.

Biodiesel is a robust solvent that can loosen 

accumulated deposits in a vehicle fuel system. When 

switching to biodiesel, additional fuel fi lter changes 

are usually required.

While biodiesel can be used undiluted (B100), it is 

generally recommended that biodiesel not constitute 

more than 20 percent of the total fuel mix. This is 

because a B20 blend achieves much of the potential 

PM2.5 reduction benefi t while minimizing potential 

NOx emissions increases.

Recently, some engine manufacturers have indicated 

that the use of biodiesel blends with greater than 5 

percent biodiesel will affect their engine warranties, 

due to concerns over the effect of biodiesel on fuel 

injectors.

In parts of the country with signifi cant biodiesel 

use, 100 percent biodiesel has in the past typically 

been 1.5–2.0 times more expensive per gallon than 

petroleum diesel. At these prices, a B20 biodiesel 

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blend would cost $0.05–$0.10 per gallon more 

than the base diesel fuel. Given recent increases in 

petroleum diesel fuel prices, biodiesel is likely to be 

more cost competitive, at least while petroleum diesel 

prices remain high. Some states also give biodiesel 

preferential tax treatment, lowering the differential 

cost compared to petroleum diesel, which is taxed at 

a higher rate.

Oxygenated Diesel Fuel. Oxygenated diesel 

(sometimes called OD) is a blend of standard petroleum 

diesel fuel with a small amount of an alcohol (up to 10 

percent) and a proprietary hydrocarbon co-solvent additive 

that keeps the alcohol from separating out of the diesel. In 

a diesel engine, the alcohol provides increased combustion 

oxygen—similar to biodiesel and with similar results 

(lowering PM2.5 emissions and potentially increasing NOx

emissions). Ethanol is low in reactivity and high in oxygen 

content, making it the preferred oxygenate, but methanol 

can also be used. 

The following implementation issues and costs apply when 

using oxygenated diesel fuel:

Oxygenated diesel can be used in virtually any diesel 

engine with no modifi cations

The alcohol increases the vapor pressure inside a 

closed fuel tank above that of typical diesel fuel, to 

levels similar to gasoline.

Oxygenated diesel typically costs $0.05–$0.10 per 

gallon more than the base diesel fuel.

Fuel-Borne Catalysts. When metal-based powdered 

catalysts in a liquid suspension are added to diesel fuel in 

very low concentrations, they can promote more complete 

combustion in a diesel engine, thus potentially reducing 

emissions of both NOx and PM2.5. Various companies sell 

proprietary catalyst packages, which may include small 

amounts of platinum, cerium, other precious metals or iron 

compounds. 

At present, no fuel-borne catalyst has been verifi ed by 

either EPA or the California Air Resources Board (CARB) 

as a stand-alone product (see below), though several 

are included as part of verifi ed systems when used in 

conjunction with a DOC or FTF. Based on the verifi cation 

results, the use of a fuel-borne catalyst appears to provide 

additional benefi ts beyond those achieved by the retrofi t 

devices alone.

The following implementation issues and costs apply when 

using fuel-borne catalysts:

Fuel-borne catalysts can be used in virtually any 

diesel engine with no modifi cations.

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182 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Some catalyst metals such as cerium pose inhalation 

hazards; therefore, since metals are increasingly 

implicated in PM health effects, fuel-borne catalysts 

that contain these metals should only be used in 

conjunction with a high-effi ciency DPF.

While catalyst formulations can theoretically be 

added by the operator directly to the fuel tank 

on individual pieces of equipment, this is not 

recommended. In order to better monitor and control 

dosage, on-board or at-the-pump dosing systems 

should be used, or the fuel supplier can add catalyst 

to bulk fuel.

Fuel-borne catalysts typically add $0.05–$0.06 per 

gallon to fuel costs.

Some manufacturers claim that fuel-borne catalysts 

can increase fuel economy by up to 5 percent, but 

these claims have not been confi rmed through EPA 

verifi cation testing (see below).

Synthetic Diesel Fuel. The Fischer Tropsch process can 

be used to make a high-quality liquid fuel from natural gas 

that has fuel properties very similar to those of standard 

diesel. With virtually zero sulfur and naturally high cetane, 

synthetic diesel can be used in any diesel engine without 

modifi cation. Preliminary emissions testing has shown 

that synthetic diesel fuel produces fewer PM and NOx

emissions than standard petroleum diesel in at least some 

diesel engines. Several energy companies are currently 

developing manufacturing facilities to produce this fuel on 

a pilot basis, but it is not commercially available anywhere 

in the U.S. today and is not expected to be for a number of 

years.

Technology Verifi cation Programs

In order to provide end-users with standardized 

information on the effectiveness of various retrofi t and 

alternative diesel fuel technologies, both EPA and CARB 

operate technology verifi cation programs (EPA, 2005a; 

CARB, 2005). Manufacturers who want to receive 

verifi cation must submit test results from standard 

emissions tests, along with information on the limitations 

and special requirements of the technology (e.g., minimum 

fuel sulfur level). CARB also requires manufacturers to 

provide minimum warranties for their products.

The EPA and CARB programs have slightly different 

requirements, but each organization has agreed to provide 

reciprocity to products verifi ed under the other’s program. 

The EPA program requires manufacturers to verify a 

product or technology separately for each of a number 

of different engine families and also reports the actual 

emissions reductions achieved for NOx, PM,5

 HC and CO. 

5. While these programs do not distinguish between PM2.5 and total PM, 

virtually all particulate produced by most diesel engines is less than 2.5 

micrometers in diameter. 

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The CARB program also provides verifi cation for specifi c 

engines and engine families. However, it separates 

technologies into three levels, based on emissions 

reduction effectiveness for PM, and it only reports the 

level that a product falls into, not the actual PM reductions 

achieved. The CARB categories include Level 1 (greater 

than 25 percent PM reduction), Level 2 (greater than 50 

percent PM reduction) and Level 3 (greater than 85 percent 

PM reduction). In the case of technologies that also reduce 

NOx, the actual NOx control-effectiveness is reported.

Either EPA or CARB, or both, has verifi ed at least one 

commercial product for each of the retrofi t technologies 

and alternative diesel fuels discussed above, except NOx

adsorbers and oxygenated diesel fuel. In addition, a 

number of commercial products have been verifi ed that 

combine several technologies together (e.g., SCR plus 

DPF, NRC plus DPF, DOC plus fuel-borne catalyst). In 

addition, several commercial products have been verifi ed 

that combine engine modifi cations to reduce NOx with 

after-treatment to reduce PM. 

The latest information on verifi ed technologies appears on 

the EPA and CARB websites. (See references at the end of 

this chapter.)

In addition to the EPA and CARB verifi cation programs, 

the Swiss Agency for the Environment, Forests and 

Landscape has operated a verifi cation program specifi cally 

for DPFs since the early 1990s. This program focuses on 

evaluating fi ltration effi ciency and durability specifi cally 

for particles between 20 and 300 micrometers in size.

The Swiss Agency publishes a list of fi lters that meet its 

stringent criteria for fi ltration effi ciency and durability, 

including greater than 95 percent reduction of total particle 

count (Suva, 2005). This list is called the VERT list. 

VERT-approved fi lters are recognized as “best available 

control technology” to reduce diesel PM emissions by 

numerous European environmental agencies, as well as by 

the U.S. Mine Safety and Health Administration. Under 

its verifi cation program, CARB accepts VERT test results 

but requires supplemental proof of compatibility with 

the particular diesel engines proposed for retrofi t. Some 

VERT-approved technologies are commercially available 

in the U.S. and could be considered by states as acceptable 

retrofi t technologies regardless of their EPA or CARB 

verifi cation status. 

Idle Reduction

The primary role of a diesel engine in most vehicles is to 

provide power to move the vehicle down the road or around 

the work site. However, most onroad and nonroad diesel 

equipment has auxiliary loads (pumps, air compressors, 

heating/air conditioning, etc.) that are also supplied by the 

engine, both when the equipment is moving and when it is 
 Chapter 12 - Diesel Engine Technologies 183

Some systems are available for retrofi t on locomotive 

engines without electronic control. These systems have 

their own ECM, as well as various sensors to monitor 

the engine and other vehicle systems. The systems are 

designed to shut down the engine automatically and to 

restart it as required to maintain appropriate engine coolant 

temperature, brake air pressure and battery voltage, etc. 

The following implementation issues and costs apply when 

using engine idle management systems:

Automatic shutdown systems will not cause vehicles 

to stall in traffi c since they are programmed not to 

shut down the engine with the vehicle in gear. 

Automatic shutdown on electronically controlled 

engines does not require any new equipment to be 

added to the vehicle.

Shutdown/restart systems for non-electronically 

controlled engines require installation of an ECM 

and sensors.

Basic automatic idle shutdown is available on 

electronically controlled engines at no extra cost.

Shutdown/restart systems cost $1,000–$1,500 for 

onroad Class 8 trucks and $5,000–$10,000 for 

locomotives.6

Electrically-Driven Auxiliary Systems. Some 

vehicle auxiliary loads are driven directly by the engine 

(e.g., cab heating), while others are supplied electrically 

but are indirectly powered by the engine through the 

engine-driven alternator (e.g., air conditioning). Various 

companies sell equipment that will allow engine-driven 

loads to be driven electrically and/or allow electrical loads 

to be supplied even with the engine off. Some of these 

technologies rely on the engine’s existing starter battery to 

6. Information on all idling reduction technology costs is taken from the 

EPA website: www.epa.gov/otaq/smartway/idling technologies.htm.

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stationary. 

In certain situations, the fact that a vehicle operator must 

idle the vehicle’s very large diesel engine in order to supply 

a fairly small load results in excess emissions. Common 

examples include long-haul truck drivers who leave their 

trucks running all night in order to provide lights and 

heating/cooling in the truck cabin while they are sleeping, 

or charter bus operators who idle their buses while waiting 

for their passengers to return from an outing—again to 

maintain comfort in the bus cabin. 

Opportunities exist to reduce total vehicle emissions by 

fi nding an alternate means to supply these auxiliary loads, 

thus allowing the operator to shut off the main engine. 

Approaches include adding equipment to the vehicle (e.g., 

a battery system or a small auxiliary engine) or installing 

infrastructure where specifi c vehicles congregate (e.g., 

electrical connections at truck stops or waiting facilities 

for bus drivers at major tourist attractions). 

Besides onroad trucks and buses, certain types of nonroad 

diesel equipment may also be a good target for idle 

reduction efforts: in particular, switchyard locomotives 

and some passenger and container ships that have high onboard electrical loads while in port. These loads, which 

are usually supplied by on-board diesel engines, could 

be supplied by the land-side electrical grid, resulting in 

signifi cant net emissions reductions.

Depending on how much idling is eliminated, idle 

reduction technologies can reduce total fuel consumption 

by up to 15 percent on trucks and 25 percent on 

locomotives (Argonne, 2005), with coincident reductions 

in NOx and PM emissions. In some cases, the required 

idle reduction equipment will pay for itself in a relatively 

short time through fuel savings.

The following is a general description of the types of 

idle reduction technologies available for both onroad and 

nonroad equipment.

Engine Idle Management. The control module in an 

electronically controlled engine can perform a number 

of functions, including automatically shutting down the 

engine after it has been idling for a certain period of time. 

While this does not address idling required to supply 

auxiliary loads, automatic shutdown can complement 

efforts to educate vehicle operators to eliminate truly 

unnecessary idling. This capability is standard on 

virtually all modern, electronically controlled engines, 

but must be turned on by a maintenance technician using 

software provided by the engine manufacturer. Some 

engine manufacturers sell a slightly more sophisticated 

system that can also restart the vehicle as required to 

maintain engine coolant and/or cab temperatures. 

Auxiliary Engine Installed on a Truck

Courtesy of Pony Pack, Inc.
184 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

supply the required electrical power, while others include 

additional supplementary batteries for longer service time. 

The following implementation issues and costs apply when 

using electrically-driven auxiliary systems:

In general, equipment must be added to the vehicle. 

Space requirements and installation time vary 

signifi cantly by system.

Costs are $500–$4,000 for onroad Class 8 trucks, 

depending on whether heating or air conditioning 

loads are covered and whether a supplementary 

battery is provided.

Auxiliary Power Units. The most versatile way to 

power various vehicle auxiliary loads with the main engine 

off is to use an auxiliary power unit. These units combine 

a small diesel engine and generator to provide electrical 

power for heating, air conditioning, pumps, lighting, etc. 

The engine is sized to match the required load, so that 

using these systems is much more effi cient than idling the 

vehicle’s much larger main engine.

In some cases these are stand-alone units that provide 

heated/cooled air directly to the vehicle cab, as well as a 

place to plug in standard electrical equipment. In other 

cases, there may be a high degree of integration with 

existing vehicle heating, air conditioning, lighting and 

other systems. 

The following implementation issues and costs apply when 

using auxiliary power units:

Equipment must be added to the vehicle. Space 

requirements, installation time and degree of 

integration with existing vehicle systems vary 

signifi cantly.

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Costs are $6,000–$9,000 for onroad Class 8 trucks 

and $30,000–$40,000 for locomotives.

Supplementary Diesel Heating Systems. Cab heat 

and/or heat to maintain engine coolant temperature for 

easy starting can be supplied by a diesel fuel-fi red heater 

(similar in design to those used for residential heating, but 

much smaller). Power for the heater’s fuel pump is supplied 

by the vehicle battery. Heated air can be supplied from the 

heater directly to the cab, or the heater can be used to heat 

the engine coolant and cab heat can be supplied through 

the vehicle’s normal heating system. Some systems include 

timers for automatic starting as well as thermostats to 

maintain specifi c cab temperatures.

The following implementation issues and costs apply when 

using supplementary diesel heating systems:

Installation is generally straightforward and required 

fuel is supplied from the vehicle’s existing fuel tank.

Costs are $900–$3,000 for onroad Class 8 trucks, and 

$15,000–$20,000 for locomotives.

Grid Power Systems. The electrical power required 

for on-vehicle auxiliary loads can be supplied from the 

electrical grid rather than being generated on-board. 

However, this always requires that infrastructure be 

installed at locations where vehicles congregate (e.g., trucks 

stops/rest stops). Some systems require only this fi xed 

infrastructure to provide heated/cooled air to the truck 

cab along with lighting and a place to plug in electrical 

equipment. These services are usually bundled with other 

amenities, such as telephone and cable TV service.

Another approach is to supply electrical power to the 

vehicle from fi xed infrastructure as a means of providing 

heating/cooling using the truck’s existing on-board 

systems. In this case, modifi cations must also be made to 

the truck, so that its existing electrical systems can accept 

grid-supplied power.

Power plug-in units can also be designed for locomotives; 

these generally require both fi xed infrastructure and 

modifi cations to the vehicle itself. This is an approach that 

may be well suited to commuter trains and yard switchers, 

but it is unlikely to be effective for many long-haul 

locomotives. 

The following implementation issues and costs apply when 

using grid power systems:

In all cases, fi xed infrastructure must be installed at 

likely locations where truckers will stop to rest.

Depending on the system, modifi cations may be 

necessary to enable the truck to accept and use power 

•

•

•

•

•

Shore Power Idle Reduction System

Courtesy of IdleAire 

Technologies, Inc.
 Chapter 12 - Diesel Engine Technologies 185

from the grid.

Truck modifi cations (if required) cost $100–$2,000 

per vehicle.

The cost of installing fi xed infrastructure can be 

$5,000 or more per parking space. Generally, this 

cost is recovered through the charges levied for use of 

the system by truckers. Depending on what services 

are provided, these charges can range from $0.50 to 

$1.50 per hour.

Hybrid Electric Locomotive. Typical locomotives are 

propelled by electric motors. Electricity to power these 

propulsion motors is produced on board using a very 

large diesel engine coupled to a generator. The diesel 

engine is sized to provide the peak power needed to start 

the locomotive from a stop and to pull large loads up an 

incline.

Unlike long-haul locomotives, whose diesel engines work 

at or close to peak load for much of the time, switcher 

yard locomotives operate in short bursts and their diesel 

engines spend a lot of time at idle or working at very low 

loads. This type of duty cycle is appropriate for a “hybrid 

electric” drive system, in which the diesel engine is sized 

for the average load (and can therefore be much smaller), 

while peak loads are provided by a battery pack.

At least one company has developed such a hybrid switcher 

locomotive. It uses a 125 horsepower diesel (smaller than 

the engines used in Class 8 trucks) and 60,000 pounds of 

lead-acid batteries. The propulsion motors are powered by 

the batteries and the diesel engine continuously charges 

the batteries as they become depleted. This confi guration 

is more effi cient than using a large diesel engine and 

completely eliminates unproductive engine idling. 

The following implementation issues and costs apply when 

using hybrid electric locomotives:

This is a new technology that is currently undergoing 

prototype testing.

Batteries are expected to last over ten years, but this 

has not been proven. 

Existing locomotives could be converted in lieu of an 

engine rebuild.

Conversion of an old locomotive costs approximately 

$200,000, which is generally competitive with engine 

rebuilds, assuming that acceptable battery life can be 

achieved (Argonne, 2005). 

Dock Electrifi cation. Some ships, while docked in port, 

have large electrical loads that are supplied by onboard 

diesel-driven auxiliary generators. If this power were 

instead provided from the land-side electrical grid, net PM 

•

•

•

•

•

•

and NOx emissions would be reduced signifi cantly in most 

cases. 

Dock electrifi cation requires both land-side infrastructure 

and expensive modifi cations to the ships themselves. 

This approach is not practical for all ships, but it can be 

cost-effective for individual vessels with a large number 

of long-duration port calls in the same location and high 

dock-side electrical loads. The ship types most likely 

to be good candidates for dock electrifi cation include 

cruise ships, refrigerated container vessels and some 

large tankers. See Chapter 17, Marine Ports, for a full 

discussion of dock electrifi cation.

References

Argonne National Laboratory, Transportation and 

Technology R&D Center. Reducing Heavy Vehicle Idling,

accessed October 4, 2005, from: www.transportation.anl.

gov/research/technology-analysis/idling.htm.

California Environmental Protection Agency, Air 

Resources Board (CARB). Diesel Emission Control 

Strategies Verifi cation, accessed November 1, 2005, from: 

www.arb.ca.gov/diesel/verdev/verdev.htm.

Clean Air Initiative for Cities around the World. Clean Air 

Initiative: About Us, accessed November 1, 2005, from: 

www.cleanairnet.org.

Clean Air Task Force. Diesel Engines: Emissions Controls 

and Retrofi ts, 2005. www.catf.us/publications/factsheets/

Diesel_Controls_and_Retrofi ts.pdf.

DieselNet. Online Information Service on Clean Diesel 

Engines and Diesel Emissions, accessed December 15, 

2005, from: www.dieselnet.com.

Manufacturers of Emissions Controls Association 

(MECA). Independent Cost Survey for Emissions Control 

Retrofi t Technology, December 2000.

New York City Department of Design & Construction. 

Local Law 77: DDC Ultra-Low Sulfur Diesel Manual, 

prepared by Gruzen Samton LLP and M.J. Bradley & 

Associates, June 2004.

Northeast States for Coordinated Air Use Management 

(NESCAUM). Heavy-Duty Diesel Emissions Reduction 

Project Retrofi t/Rebuild Component (EPA 420-R-99-94), 

March 1999. 

Research Triangle Institute (RTI) and Southwest Research 

Institute. Environmental Technology Verifi cation Test 

Report of Mobile Source Emissions Control Devices, 

Donaldson Company, Inc. Series 6000 Diesel Oxidation 
186 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Catalyst Muffl er and SpiracleTM Closed Crankcase 

Filtration System, September 30, 2003.

Suva, Inc. Product Certifi cation, accessed December 

15, 2005, from: www.suva.ch/en/home_en/suvapro/

zertifi zierung/produktezertifi zierung.htm.

U.S. Environmental Protection Agency (EPA). Reducing 

Air Pollution from Nonroad Engines (EPA-420-F-03-011), 

April 2003. www.epa.gov/otaq/cleaner-nonroad/f03011.

pdf.

U.S. Environmental Protection Agency (EPA). SmartWay 

Transit Partnership: Idling Reduction Technologies,

accessed October 4, 2005, from: www.epa.gov/otaq/

smartway/idlingtechnologies.htm.

U.S. Environmental Protection Agency (EPA), Offi ce of 

Transportation and Air Quality. Voluntary Diesel Retrofi t 

Program: Verifi ed Products, accessed November 1, 2005, 

from: www.epa.gov/otaq/retrofi t/retroverifi edlist.htm. 

(2005a)

U.S. Environmental Protection Agency (EPA), Offi ce of 

Transportation and Air Quality. Voluntary Diesel Retrofi t 

Program: Cleaning Older Engines, November 4, 2005. 

www.epa.gov/otaq/retrofi t/. (2005b)
188 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

The onroad heavy-duty vehicle sector is composed of a 

wide variety of vehicles, from 18-wheel tractor-trailer 

combinations, to school and transit buses, to dump trucks 

and refuse haulers. These vehicles can be found in large 

numbers on major highways as well as on urban streets. 

The vast majority are powered by diesel engines. 

Heavy-duty vehicles are categorized by weight class. In 

terms of numbers of vehicles, and especially fuel used 

annually, the heaviest Class 8 vehicles dominate. In 2002 

there were over 2,082,600 Class 8 trucks on the road in 

the U.S. (U.S. Census Bureau, 2004) and they used over 

17 billion gallons of diesel fuel (Davis, 2004).

The majority of these Class 8 trucks are long-haul tractortrailers used to move goods over the nation’s highways. 

Other examples of Class 8 vehicles include transit buses 

and refuse haulers. 

Truck traffi c in the U.S. is growing. The number of 

miles traveled annually by Class 8 trucks is expected to 

increase by approximately 40 percent through 2020 (EPA, 

2000a). While future emissions regulations will mitigate 

the air quality impacts of increased miles traveled, heavyduty onroad vehicles are, and will remain, a signifi cant 

contributor to direct fi ne particulate matter (PM2.5) and 

PM2.5-precursor emissions.

While the number of heavy-duty trucks on the road 

is signifi cantly smaller than the number of light-duty 

gasoline-fueled cars, their air quality impact is greater 

Chapter 13

Diesel Trucks and Buses

Table 13.1

Heavy-Duty Truck Classifi cations

Class Gross Vehicle Weight Rating (lb)

2B 8,501–10,000 

3 10,001–14,000 

4 14,001–16,000 

5 16,001–19,500 

6 19,501–26,000 

7 26,001–33,000 

8 > 33,000 

Source: U.S. Census Bureau, 2004
 Chapter 13 - Diesel Trucks and Buses 189

because current diesel vehicles emit signifi cantly more 

PM2.5 and nitrogen oxides (NOx) for each gallon of fuel 

burned than do gasoline vehicles. This is partly due to 

the nature of diesel combustion and partly due to a lag in 

EPA emissions regulations for diesel engines. In addition, 

heavy-duty diesel vehicles and engines tend to last much 

longer than gasoline cars and engines, so it takes longer 

for more stringent regulations to have a signifi cant impact. 

This chapter discusses the current and projected inventory 

of direct PM2.5 and PM-precursor emissions from onroad 

heavy-duty vehicles, available regulatory authority to 

address these emissions from new and existing vehicles, 

and the control strategies that state and local authorities 

could consider to reduce emissions from existing 

heavy-duty vehicle fl eets as they develop their State 

Implementation Plans (SIPs). Some of the strategies 

discussed involve the use of various diesel retrofi t 

technologies. These technologies are described in Chapter 

12, Diesel Engine Technologies.

Sector Profi le

The vast majority of direct PM2.5 emissions and PM2.5-

precursor emissions from heavy-duty onroad vehicles 

come from the combustion of diesel fuel in diesel engines. 

Almost all of the PM emissions in the exhaust of these 

vehicles is PM2.5. Gasoline powered heavy-duty vehicles 

do exist, but they account for less than 3 percent of PM2.5

and 6 percent of NOx emissions from onroad sources. In 

addition, tire wear and brake wear together account for 

less than 2 percent of PM2.5 emissions from heavy-duty 

vehicles. About a quarter of the PM emissions from tire 

wear is PM2.5, and close to half of the PM emissions from 

brake wear is PM2.5 (EPA, 2005a). 

Exhaust from heavy-duty diesel vehicles accounts for 

about 65 percent of direct PM2.5 emissions from onroad 

vehicles (EPA, 2005a). This is less than 2 percent of the 

total inventory of direct PM2.5 emissions, including 

stationary sources and nonroad vehicles. However, the 

hazardous nature of diesel exhaust and the proximity of 

diesel exhaust sources to sensitive populations, particularly 

in urban areas, magnifi es the health impact. Diesel exhaust 

is known to contain over 40 substances listed by EPA as 

hazardous air pollutants, 15 of which have been listed 

by the International Agency for Research on Cancer as 

known, probable or possible human carcinogens. Many of 

these substances are adsorbed onto emitted diesel exhaust 

particles. For this reason, the California Air Resources 

Board (CARB) has formally designated diesel PM as a 

toxic air contaminant (CARB, 1998). 

Exhaust from heavy-duty diesel engines also accounts for 

about 50 percent of NOx emissions from onroad vehicles 

and about 20 percent of all NOx emissions, including those 

from nonroad diesel and stationary sources (EPA, 2005a). 

All mobile sources, including light- and heavy-duty onroad 

vehicles and nonroad equipment, produce about 2–4 

percent of total sulfur dioxide (SO2) emissions nationally 

(EPA, 2005a). Mobile source SO2 emissions will be 

reduced further beginning in 2006, when allowable fuel 

Table 13.2

Heavy-Duty Truck Statistics (2002)

Class No. Trucks 

(x000)

VMT (million 

miles)

Fuel Use 

(million 

gallons)

2B 396.7 5,031.2 318.2

3 621.1 8,428.6 1,075.1

4 287.3 4,184.2 533.7

5 291.1 3,949.2 503.7

6 855.8 11,361.3 1,449.1

7 419.1 5,726.7 995.9

8 2,082.6 100,167.0 17,420.3

VMT = vehicle miles traveled

Source: U.S. Census Bureau, 2004

Table 13.3

Diesel Truck and Bus Emissions (2002)

Category PM2.5 (tons/year) SO2 (tons/year) NOx (tons/year)

Heavy-duty diesel 

vehicles (highway)

97,000 105,000 3,378,000

% of highway vehicle 

emissions

65% 38% 46%

% of total mobile 

source emissions

22% 15% 29%

Source: EPA, 2005f
190 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

sulfur levels for both gasoline and diesel fuel will decline 

by over 90 percent (see below). 

Efforts to reduce direct PM2.5 and PM2.5-precursor 

emissions from the onroad diesel sector should focus on 

reducing exhaust emissions of both direct PM2.5 and NOx. 

Regulatory Authority

As discussed in Chapter 4, the Clean Air Act gives EPA 

primary authority to regulate emissions from new onroad 

vehicles, including heavy-duty onroad vehicles. California 

has authority to adopt its own emissions standards for these 

vehicles, as long as they are at least as stringent as federal 

standards. Other states can adopt either the California or 

the federal standards. States and localities are free to set 

their own standards for existing onroad vehicles. As we 

discuss below, California standards for new heavy-duty 

onroad vehicles largely track federal standards.

New Vehicle Standards

EPA considers any vehicle over 8,500 pounds gross vehicle 

weight to be heavy-duty and therefore subject to different 

regulations than light-duty cars and trucks. The exception 

to this is that under EPA Tier 2 regulations for light-duty 

vehicles, certain very large sport utility vehicles (SUVs) 

and passenger vans used for personal transportation 

(8,500–10,000 lb gross vehicle weight) are re-classifi ed 

as medium-duty passenger vehicles and are subject to the 

light-duty vehicle rules (DieselNet, 2005). 

Unlike light-duty vehicles that are tested and certifi ed 

at the vehicle level using a chassis test, only the engines 

themselves are certifi ed for heavy-duty vehicles, using an 

engine test. Consequently, the numerical emissions limits 

are not expressed as grams per mile, but rather as grams 

per brake-horsepower hour (g/bhp-hr), equivalent to grams 

of emissions per unit of work done by the engine. 

EPA fi rst set exhaust smoke opacity standards for new 

heavy-duty onroad diesel engines beginning in model 

year 1970. Starting in model year 1974, new engines were 

required to meet numeric emissions limits for carbon 

monoxide (CO) and NOx + hydrocarbons (HC), but PM was 

not regulated until 1988. Between 1988 and 1998, the EPA 

limits for HC and CO remained the same, but allowable 

levels of both NOx and PM were reduced in several steps. 

At 4.0 g/bhp-hr NOx and 0.10 g/bhp-hr PM, the emissions 

limits for the 1998 model year were 63 percent and 83 

percent lower, respectively, than those for the 1988 model 

year.

In 1997, EPA adopted an even lower standard for heavyduty diesel engine NOx emissions to take effect in the 2004 

model year. The next year EPA signed a consent decree 

with the six major heavy-duty engine manufacturers to 

settle EPA claims. According to EPA, manufacturers had 

for a number of years been using an “emissions defeat 

device” that modifi ed engine control software to improve 

fuel economy, but that increased NOx emissions during 

certain high-speed steady-state (highway) driving modes 

that were not fully captured during the certifi cation test 

cycle. Among other remedies, the consent decree mandated 

Table 13.4

EPA Emissions Standards for New Heavy-Duty Onroad Diesel Engines (g/bhp-hr)

Model Year Beginning HC CO NOx PM

1988 1.3 15.5 10.7 0.60

1990 1.3 15.5 6.0 0.60

1991 1.3 15.5 5.0 0.25

1993 1.3 15.5 5.0 0.25 (0.10a

)

1994 1.3 15.5 5.0 0.10 (0.07a)

1996 1.3 15.5 5.0 0.10 (0.05a

)

1998 1.3 15.5 4.0 0.10 (0.05a)

2004 0.5 15.5 2.5b 0.10 (0.05a

)

2007c 0.14 15.5 0.2d 0.01

g/bhp-hr = grams per brake-horsepower hour

a. This lower PM limit applies to urban transit buses only.

b. This limit is for NOx + non-methane hydrocarbons (NMHC). 

c. After 2007, any crankcase emissions must be added to tailpipe emissions subject to these limits.

d. The new NOx limits are phased in between the 2007 and 2010 model years on a percent-of-sales basis. The 2007 rules also add new 

steady-state tests and not-to-exceed limits for NOx.

Source: DieselNet, 2005
 Chapter 13 - Diesel Trucks and Buses 191

the 2004 NOx standard of 2.5 g/bhp-hr for engines built 

after October 2002. Under the consent decree, engine 

manufacturers were also required to develop modifi ed 

software for model year 1993–1998 engines that would 

reduce off-cycle highway NOx emissions (this software is 

often referred to as an ECM or chip “refl ash”) and to make 

this software available to vehicle owners free of charge. 

The consent decree required that all engines be upgraded 

with this new software at the time of normal engine 

overhaul or rebuild, which was assumed to occur after 

200,000 to 300,000 miles in service (U.S. v Caterpillar, 

1999). 

In December 2000, EPA adopted a NOx standard of 0.20 g/

bhp-hr and a PM standard of 0.01 g/bhp-hr for new onroad 

heavy-duty diesel engines. This PM standard will go into 

full effect in the 2007 model year, while the NOx standard 

will be phased in between 2007 and 2010 on a percent-ofsales basis. 

The 2007 emissions standards introduce additional steadystate tests and not-to-exceed limits in the certifi cation 

process, to ensure that defeat devices like those that led to 

the 1998 consent decree will no longer be possible. The 

2007 regulations also require that crankcase vent emissions 

from all diesel engines be controlled (DieselNet, 2005). 

Previously, engines with turbo-chargers were allowed to 

vent their crankcase emissions to the atmosphere; these 

emissions were thus not included in the exhaust limits. 

Because the onroad heavy-duty fl eet turns over much more 

slowly than the light-duty fl eet, there are still signifi cant 

numbers of vehicles with unregulated or marginally 

regulated pre-1990 engines on the road. Even so, over 

the next 15 years current and pending EPA regulations 

will begin to have a signifi cant effect. Based on normal 

fl eet turn-over, EPA estimates that annual NOx and PM 

emissions from heavy-duty onroad vehicles will fall by 22 

percent and 37 percent respectively through 2010, and by 

77 percent and 84 percent respectively through 2020, as 

new vehicles enter the fl eet and older vehicles are retired 

(EPA, 2000b). This decline in annual emissions will occur 

despite a projected 40 percent increase in annual vehicle 

miles traveled through 2020.

Urban Bus Retrofi t/Rebuild Rule

In 1993, EPA fi nalized a retrofi t/rebuild rule that applies 

to urban transit bus engines built before 1994. The rule 

requires that a certifi ed retrofi t/rebuild kit be used every 

time one of these engines is rebuilt or overhauled. These 

kits will either reduce PM emissions by 25 percent 

compared to the original certifi cation level of the engine, 

or will achieve PM emissions of 0.1 g/bhp-hr (EPA, 1998). 

To date, EPA has not proposed retrofi t/rebuild requirements 

for any other onroad diesel engines.

Fuel Quality

Congress has also given EPA authority to regulate the 

quality of fuel and fuel additives used in vehicles, based 

on direct health effects from the fuel itself and the effect of 

fuel on the ability of vehicles to meet emissions standards. 

EPA began to regulate the sulfur content of onroad diesel 

fuel in 1994, setting a limit of 500 parts per million (ppm). 

In order to allow the use of advanced catalytic emissions 

controls that will be required to meet the 2007 PM and 

NOx standards, the most recent EPA regulations further 

reduce the allowable level of sulfur in onroad diesel fuel to 

15 ppm beginning in late 2006 (EPA, 2001).

As discussed in Chapter 4, The Clean Air Act, if EPA 

has regulated a fuel characteristic or component, states 

other than California may not adopt either their own or 

California’s regulation—they must follow the federal 

regulation. The only exception to this is the situation in 

which the Administrator fi nds that state regulation is 

necessary for achieving the National Ambient Air Quality 

Standards (NAAQS). On the other hand, California may 

adopt its own fuel regulations.

Other Regulations: California

As has already been noted, California has authority under 

the Clean Air Act to set its own emissions standards for 

new vehicles and to establish requirements for fuels and 

fuel additives.

California’s regulation of onroad heavy-duty diesel 

engines began in 1973, but PM emissions were not 

regulated until 1987, one year before EPA began regulating 

PM. In addition, California’s 1987 NOx standard of 6.0 g/

bhp-hr was not matched by federal standards until 1990. 

However, with the exception of engines for urban buses, 

the numerical emissions limits set by California have been 

virtually identical to EPA limits since then. California 

adopted more stringent standards for urban buses between 

model years 2004 and 2006; these standards included fl eet 

averaging and mandatory fl eet-wide emissions reduction 

requirements. For the 2005 model year, California also 

adopted supplemental steady state tests and not-to-exceed 

limits that will not be mandated by EPA until model year 

2007 (DieselNet, 2005). 

After 2007, California’s numerical emissions limits for 

onroad heavy-duty diesel engines are virtually identical to 

EPA standards. However, in July 2005 California adopted 

rules that will require the addition of on-board diagnostic 

systems (OBD) for onroad diesel engines beginning in the 

2010 model year (CARB, 2005d). 

Similar to the OBD systems required for light-duty vehicles 

under current EPA and California rules, these diesel OBD 

systems will be required to monitor engine systems that 

affect emissions and to warn the driver of failures that are 
192 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

likely to increase emissions, so that they can be repaired. 

Like inspection and maintenance (I&M) programs, OBD 

systems are designed to ensure that vehicles continue to 

meet new vehicle emission standards throughout their life.

All of the California requirements noted in this section 

apply to new vehicles. The California programs that are 

discussed in later sections of this chapter cover existing

vehicles.

State Authority

Despite limiting the ability of state and local areas to 

regulate new vehicles, the Clean Air Act allows them to 

set standards for existing onroad vehicles. In fact, this 

responsibility falls primarily to the states, with EPA’s 

role in regulating existing vehicles limited to ensuring 

compliance with new vehicle standards throughout the 

defi ned useful life of the vehicle, and potentially regulating 

emissions from re-built engines used in buses and other 

heavy-duty onroad vehicles (see above). 

Emissions Control Opportunities

Many of the emissions reduction technologies that are and 

will be applied to new onroad diesel engines to comply 

with current and future EPA regulations can also be 

applied to existing engines and vehicles to reduce their 

emissions. There are three main options for reducing 

emissions from a diesel vehicle or fl eet: use a cleaner 

engine, use a cleaner fuel or add a retrofi t device.

In addition, changes to heavy-duty vehicles, to their 

operations or to the transportation system that reduce total 

fuel usage can reduce total emissions and save vehicle 

operators money.

Use a Cleaner Engine

New onroad diesel engines produce less than 50 percent of 

the NOx and less than 20 percent of the PM produced by 

engines built 15 years ago. Most of these reductions have 

come from fundamental changes in diesel engine design. 

Removing older engines from service and replacing them 

with new engines can therefore have a large emissions 

benefi t. 

Table 13.5

California Air Resources Board (CARB) 

Emission Standards for New Heavy-Duty Onroad Diesel Engines (g/bhp-hr)

Model Year HC CO NOx PM

Onroad Truck

1987 1.3 15.5 6.0 0.60

1991 1.3 15.5 5.0 0.25

1994 1.3 15.5 5.0 0.10

1998 1.3 15.5 4.0 0.10

2004 0.5 15.5 2.5a 0.10

2005 0.5 15.5 2.5b 0.10

2007 0.14 15.5 0.2 0.01

Urban Bus

1991 1.3 15.5 5.0 0.10

1994 1.3 15.5 5.0 0.07

1996 1.3 15.5 4.0 0.05

2004c 0.05 5.0 0.5 0.01

2007 0.14 15.5 0.2 0.01

g/bhp-hr = grams per brake-horsepower hour

a. This limit is for NOx + non-methane hydrocarbons (NMHC). 

b. Adds a Supplemental Engine Test for certifi cation, and not-to-exceed limits of 1.25x these numerical values anywhere on the engine 

map.

c. This is for diesel engines; there are different limits for alternative fuel engines. CARB also imposed fl eet average and mandatory fl eet 

reduction requirements for diesel transit bus fl eets. 

Source: DieselNet, 2005
 Chapter 13 - Diesel Trucks and Buses 193

For most older vehicles it is more cost-effective to retire 

the vehicle itself. However, for some specialty vehicles—

for example, a large construction crane—where the engine 

represents a relatively small percentage of the vehicle’s 

total value, “repowering” an old vehicle with a new engine 

may be the preferred alternative. 

In limited cases it is also possible to cost-effectively 

modify existing engines to incorporate more modern 

design elements and equipment—for example, improved 

injectors—that reduce emissions. This approach would 

also include refl ashing of 1993–1998 model year engines 

with upgraded software to reduce off-cycle highway NOx

emissions. (See above discussion of 1998 consent decree.)

Use a Cleaner Fuel

Some alternative formulations of diesel fuel produce lower 

emissions of NOx and/or PM in existing engines than 

standard onroad diesel fuel. The most common of these 

cleaner fuels are described in Chapter 12, Diesel Engine 

Technologies.

Heavy-duty engines are also available for trucks and buses 

that operate on natural gas and produce signifi cantly lower 

PM emissions than current diesel engines. Natural gas 

engines have PM emissions essentially equivalent to the 

2007 EPA PM standards for new diesel engines. These 

natural gas engines are also certifi ed to produce 30–50 

percent lower NOx emissions than the current EPA NOx

standards for new diesel engines (DOE, 2005). 

While it is technically possible to modify existing diesel 

engines to operate on natural gas, using a purpose-built 

natural gas engine is generally preferred (ICCT, 2005). 

Converting an existing diesel vehicle to natural gas also 

requires that the fuel system be extensively modifi ed to 

use high-pressure gaseous fuel in lieu of liquid diesel fuel 

and that high-pressure natural gas fueling stations are 

available. Given the cost and current limited availability 

of natural gas fueling stations, conversion to natural gas is 

most appropriate for fl eet vehicles that are centrally fueled 

and that operate within a limited geographic area. 

Add a Retrofi t Device

As described in Chapter 12, there are a number of retrofi t 

technologies that can be installed on existing diesel 

vehicles to reduce emissions. Most of these are aftertreatment devices that install in the exhaust system; they 

do not reduce the emissions produced by the engine rather 

they clean up the exhaust after it has left the engine, but 

before it is emitted to the atmosphere. Most of these 

technologies rely on some kind of catalytic process and 

can reduce either PM or NOx emissions, but not both 

simultaneously. Discrete technologies can, however, be 

combined into a single commercial product to achieve 

simultaneous PM and NOx reductions.

Retrofi t devices include closed crankcase and crankcase 

fi lter systems that control crankcase vent emissions, which 

are not currently included in EPA engine emissions limits 

(but will be included beginning with the 2007 model year). 

Testing conducted on a 1998 onroad diesel engine under 

the EPA Verifi cation Program showed that PM emissions 

from the crankcase vent amounted to 16–23 percent of 

the PM emissions coming from the tail pipe (RTI, 2003). 

Controlling crankcase emissions is especially important 

in terms of reducing PM exposure for certain populations, 

such as students riding school buses (Hill, 2005).

The three main options described above for reducing 

emissions from diesel vehicles are not mutually exclusive. 

In fact, some commercially available retrofi t devices work 

better in conjunction with, or even require the use of, an 

alternative diesel fuel. Commercial products are also 

available that combine engine modifi cations with retrofi t 

devices, while engine repowering can always be combined 

with retrofi ts to reduce emissions even further. 

Fuel Economy Improvements

Other aspects of the way vehicles are designed and 

operated—besides the engine itself—can affect total 

fuel usage and emissions. While much less important 

for vehicles that operate at relatively low speeds in urban 

areas, aerodynamic characteristics play a big role in the 

fuel economy of trucks that operate at high speeds on 

highways, as does the rolling resistance of tires. Vehicle 

speed and even the way the operator drives can have a 

noticeable effect on fuel usage. In addition, the overall 

effi ciency of the nation’s transportation system for goods 

affects the total amount of fuel required to move products 

from the manufacturer to the consumer.

Technology-based approaches to reducing overall fuel 

usage for individual trucks and for the transportation 

system as a whole include the use of more aerodynamic 

trucks and trailers, the use of lower rolling resistance tires, 

the use of low-viscosity lubricants and the maintenance 

of proper tire infl ation. Operational approaches that can 

reduce fuel usage include eliminating unnecessary engine 

idling, providing driver training, reducing highway speeds 

and improving freight logistics and intermodal shipping. 

While primarily focused on reducing fuel usage, these 

approaches can also reduce total emissions of both NOx

and PM, especially from the Class 8 tractor-trailer trucks 

that are widely used to transport goods and that dominate 

the onroad heavy-duty diesel vehicle sector. 

As discussed in Chapter 15, Light-Duty Cars and Trucks, 

keeping maximum highway speeds below about 55 or 

60 miles per hour (mph) also limits fuel use, as vehicles 

operate less effi ciently at higher speeds. For cars, fuel 

economy generally deteriorates rapidly above 60 mph; 
194 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

in fact, the U.S. Department of Energy (DOE) estimates 

that fuel economy declines 5–7 percent for every fi ve mile 

per hour increase in vehicle speed above 60 mph. Diesel 

trucks and buses that lower their speed from 65 to 55 mph 

use approximately 20 percent less fuel (EPA, 2005f).

State and Local Policy Measures

Programs that encourage or mandate the retirement or 

replacement of older diesel vehicles, the use of cleaner 

fuels or diesel vehicle retrofi ts can have a large impact on 

air quality. These programs provide the most signifi cant 

opportunities for state and local areas to control and 

reduce PM and NOx emissions from onroad diesel fl eets. 

As discussed below, whether these policies are voluntary 

or mandatory, their common focus is on the application of 

new technology to existing diesel vehicles. Programs that 

result in reduced fuel usage by onroad diesel vehicles will 

also reduce PM and NOx emissions.

Voluntary Retrofi t Programs

Replacing vehicles and engines, introducing alternative 

fuels and installing retrofi t devices can be expensive. The 

Manufacturers of Emission Controls Association estimates 

that retrofi t PM control devices for Class 8 trucks cost 

between $1,000 and $10,000 per vehicle, depending on the 

type of retrofi t device (MECA, 2000). NOx control devices 

can cost as much as $20,000 per vehicle and a new engine 

can cost $30,000 or more installed. Given this expense, 

voluntary emissions reduction programs are seldom 

effective without a funding source to offset some or all of 

the cost to the vehicle owner. 

Programs to offset the cost of emissions controls for 

vehicle owners can take many forms, such as providing 

tax reduction or other tax incentives, or a direct rebate for 

some or all of the cost of implementing specifi c measures. 

However, the most common programs for heavy-duty 

diesel vehicles are grant programs. These programs 

are usually competitive, beginning with a Request for 

Proposals that specifi es the types of projects that will 

be considered. Often, proposals are evaluated for costeffectiveness (dollars per ton of reduction), with only the 

most cost-effective projects funded, or with all projects 

above a specifi ed minimum level of cost-effectiveness 

funded.

These programs generally provide a grant equal to the 

incremental cost of the action taken to reduce emissions. 

A grant program could fund any or all of the following 

types of emissions reduction projects: early vehicle 

retirement/scrappage, engine repowering, fuel switching, 

engine modifi cation or vehicle retrofi t.

The two largest grant programs currently operating are 

California’s Carl Moyer Memorial Air Quality Standards 

Program (Carl Moyer) and the Texas Emissions Reduction 

Program (TERP). According to the CARB, Carl Moyer 

has provided $184 million in grant funding for various 

emissions reduction projects throughout California since 

its inception in 1998 (CARB, 2003). Approximately 45 

percent of these funds have gone to projects to reduce 

emissions from onroad diesel vehicles. Maximum 

available funding for the current year totals $140 million. 

The 2003–2004 budget included $4.6 million for the 

purchase of new low-emitting school buses, and the 2005–

2006 budget includes $25 million to retrofi t or replace 

additional school buses (CARB, 2005b). 

Since 2001, TERP has provided $39 million in grants for 

41 onroad diesel emissions reduction projects in the 41 

Texas counties designated as nonattainment areas. Funded 

projects included vehicle replacements, repowering, 

retrofi ts, purchase of cleaner fuels and infrastructure 

development (TCEQ, 2004). As discussed in Chapter 14, 

Nonroad Equipment, TERP has also funded nonroad diesel 

emissions reduction projects. 

Both Carl Moyer and TERP make project awards based 

on a minimum level of cost-effectiveness and both are 

primarily designed to reduce NOx emissions, with a 

secondary focus on PM. Each of these programs funds 

a range of onroad diesel projects in all of the categories 

discussed above. 

In recent years, EPA has also made demonstration grants 

under its Voluntary Diesel Retrofi t Program and has 

launched a Clean School Bus Initiative. The most recent 

grants were announced in February 2005, with a total of 

$1.6 million going to 18 projects across the country. These 

projects included retrofi ts of onroad trucks and buses 

as well as construction and agricultural equipment. The 

EPA grant program requires local matching funds (EPA, 

2005b).

Over the last four years, the Puget Sound Clean Air Agency 

has also sponsored and funded approximately 3,000 

retrofi ts of transit and school buses, refuse haulers, public 

works vehicles, construction equipment and port materialhandling equipment, as well as fuel substitution for the 

world’s largest ferry fl eet. Its Diesel Solutions program 

and the Washington State Clean School Bus programs are 

both voluntary and incentive-based. The Puget Sound 

Clean Air Agency currently has appropriations of $5 

million annually to retrofi t school buses statewide (Puget 

Sound CAA, 2005).

Funding for clean air grant programs can come from a 

number of sources. The current TERP program is funded 

by surcharges on the sale or lease of new and used onroad 

and nonroad diesel vehicles, as well as by fees charged for 

commercial motor vehicle inspections and by a portion 
 Chapter 13 - Diesel Trucks and Buses 195

of fees for certifi cates of vehicle title. Funding for this 

program is expected to total approximately $150 million 

per year through 2010 (TCEQ, 2004). In its early years, 

Carl Moyer was funded through annual appropriations 

in the state budget. Beginning in fi scal year 2005, the 

program has been funded by dedicating a portion of 

fees from the state’s Smog Check program for light-duty 

vehicles, as well as by fees added to the sale of tires. Local 

air districts are also allowed to raise additional funds by 

adding $2 to the fees charged by the Department of Motor 

Vehicles (CARB, 2005b). In 2005, expected funding for 

the Carl Moyer program totals $61 million from Smog 

Check fees, $25 million from tire fees and $55 million 

raised by local districts (Lemieux, 2005). 

In New Jersey, a diesel retrofi t program adopted by 

the state legislature in June 2005 and approved by a 

substantial margin in the November 2005 general election 

will be funded by reapportioning 17 percent of the 4 

percent portion of the state’s corporation business tax 

that is currently dedicated to the remediation of leaking 

underground fuel storage tanks. This is expected to 

generate $14 million per year for retrofi ts (Iavorone, 2005). 

In 1996, the citizens of the State of New York approved 

the Clean Water/Clean Air Bond Act. Under this program, 

New York issued $1.75 billion in general obligation bonds. 

The state used the money to fund a range of environmental 

programs. Approximately $230 million was spent on air 

quality projects, including retrofi ts and fuel conversions of 

onroad diesel vehicles (NY DEC, 2005). 

A number of states have also used funds collected in 

environmental enforcement actions to fund diesel retrofi t 

projects.

Mandatory Retrofi t Programs

In addition to the voluntary programs discussed above, 

a number of states and localities have begun to mandate 

the retrofi t or replacement of onroad diesel engines in 

specifi c types of fl eets. California was the fi rst to take this 

approach, adopting a fl eet rule in 2000 for transit buses 

that mandated the use of cleaner engines, cleaner fuels 

and the retrofi tting of older vehicles. This rule is focused 

on both NOx and PM emissions. It mandates incremental 

progress over a ten-year period through more stringent 

standards for new engines as well as retrofi t requirements 

(CARB, 2005a). 

In 2003, CARB extended the same concept to other 

fl eets by adopting a mandatory retrofi t program, to be 

implemented between 2004 and 2010, for all diesel-fueled 

solid waste collection vehicles over 14,000 pounds gross 

vehicle weight. This program provides implementation 

fl exibility because it does not require the use of a specifi c 

retrofi t device. Instead, it requires the use of the Best 

Available Control Technology (BACT) that can reduce PM 

emissions to the greatest extent possible. Under the rules, 

repowering with a natural gas or cleaner diesel engine 

can be considered BACT, as can retrofi t with a retrofi t 

technology verifi ed by the CARB (CARB, 2004b). 

In April 2005, the New York City Council enacted 

legislation mandating the retrofi t of private school buses, 

city-licensed sight-seeing buses, garbage trucks used for 

all city contracts and all city-owned or -operated diesel 

vehicles. Similar to California’s regulations, these rules 

require vehicle owners to install BACT to reduce PM 

emissions (NY Mayor’s Offi ce, 2005).

The 2005 New Jersey program referenced above requires 

BACT retrofi ts for all diesel school buses, commercial 

buses, garbage trucks that are publicly owned or used 

on a publicly funded contract and other publicly owned 

onroad diesel equipment. Unlike the California and New 

York City legislation, the New Jersey program includes 

provisions to reimburse fl eet owners for the cost of the 

retrofi ts. 

Both the New York City and the New Jersey legislation 

combine direct and indirect mandates. Direct mandates 

apply to all vehicles of a given type regardless of who 

owns or uses them, while indirect mandates are imposed 

primarily through government purchasing and/or 

contracting requirements and are therefore more limited 

in scope. While government-owned and -controlled fl eets 

generally make up only a small percentage of the onroad 

diesel vehicles in a locality, the appeal of indirect mandates 

imposed through government contracting policies is that 

they are usually easier to implement. By helping to build 

an experience base and develop a commercial market for 

retrofi t products and services that can later be extended 

to private fl eets, the impact of these mandates can also 

extend beyond the specifi c vehicles they target. However, 

experience has shown that the spillover of voluntary 

actions to the private sector is usually limited absent some 

direct economic incentive. 

Other mandatory actions that state and local governments 

can take to reduce emissions from existing diesel vehicles 

include maximum vehicle age requirements for contracted 

government services like school buses and increased taxes 

and/or registration fees for older vehicles. These types of 

policies are designed to encourage retirement of the oldest, 

most polluting diesel vehicles. 

States can also follow California’s lead in mandating 

accelerated efforts to refl ash the engine control software 

in model year 1993–1998 diesel engines to reduce offcycle NOx emissions during highway driving. Under 

the 1998 consent decree between EPA and diesel engine 

manufacturers, these software upgrades were supposed to 

be completed during normal engine rebuilds. However, 
196 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

because the upgrades will also increase fuel usage during 

highway driving, vehicle owners have little incentive to 

comply. In early 2004, CARB estimated that fewer than 

10 percent of eligible engines had been upgraded (CARB, 

2004c).

In December 2004, CARB adopted a rule that requires 

owners of heavy-duty trucks, school buses and dieselpowered motor homes built between 1993 and 1999 to 

upgrade their engines by December 31, 2006 pursuant to 

a phased schedule and starting with the oldest engines. 

For the most part, the required software is already 

available and under the terms of the consent decree it 

must be provided by engine manufacturers free of charge. 

Compliance will be enforced through fi nes assessed as part 

of California’s diesel I&M program. CARB estimates that 

its rule will affect as many as 450,000 vehicles and, when 

fully implemented, will reduce NOx emissions by more 

than 35 tons per day (CARB, 2005c).

Inspection and Maintenance

Numerous studies have shown that a minority of vehicles 

create a disproportionate share of vehicle emissions 

(Niemeir, 2004). These high emitters are vehicles that are 

poorly maintained, misadjusted or have malfunctioning 

emissions control equipment. 

Under the Clean Air Act, certain ozone and CO 

nonattainment areas are required to put I&M programs in 

place for light-duty vehicles. However, these requirements 

give the states a good deal of fl exibility as to the type of 

I&M program they adopt. Moreover, even states without a 

federal I&M mandate can implement a state I&M program 

if there is no bar to their doing so under state law.

I&M programs are designed to identify high emitters and 

require vehicle owners to repair them. Inspections can be 

performed on a regular basis, usually in conjunction with 

renewal of vehicle registration or a state-mandated safety 

inspection, or randomly at the roadside after a pullover. 

Mandatory repair requirements can be enforced through 

denial of vehicle registration and/or imposition of a fi ne 

that is waived upon proof of repair. 

I&M programs for light-duty gasoline vehicles are well 

developed, and tools for measuring emissions to identify 

high emitters have evolved over time. They now include 

devices that directly measure tailpipe CO, HC and NOx

emissions, as well as devices that use information from 

OBD systems.

Currently 16 states have some kind of I&M program for 

onroad diesel vehicles, either statewide or in certain 

counties (Diesel Technology Forum, 2004). The tools 

available to identify diesel high emitters are more limited 

than those available to gasoline vehicle I&M programs. 

Virtually all of the current diesel I&M programs use 

a green light opacity meter and the SAE J1667 “snap 

acceleration” test to measure smoke emissions as a proxy 

for PM emissions; NOx, CO and HC emissions are not 

measured. 

A review of available data from current U.S. programs 

concluded that “approximately 5–7 percent of pre-1998 

vehicles record smoke emissions on the snap test in excess 

of standards” and that “smoke inspection programs are 

effective in reducing both the number of smoky vehicles 

and the average smoke opacity from any given model 

year’s vehicles” (Diesel Technology Forum, 2004).

Measured smoke opacity from diesel vehicles is highly 

dependent on test procedures and conditions, and very 

little data exist to directly correlate measured opacity 

to PM mass emissions over a typical vehicle driving 

cycle. However, a study of 20 vehicles that had failed a 

smoke opacity test using the standards set by most I&M 

programs showed that after repair, both smoke opacity and 

PM emissions as measured over the Urban Dynamometer 

Drive Schedule (UDDS) declined on most vehicles. For 

pre-1991 vehicles, smoke opacity in a snap acceleration test 

(i.e., quickly ramping up the engine from idle to maximum 

governed RPM) declined by 33 percent on average after 

repairs, while post-repair PM emissions over the UDDS 

were on average 41 percent lower. The results were 

similar for 1991 and newer vehicles. The most common 

repairs performed were replacement of injectors and 

injector pumps. Repair costs ranged from $85 to $2,053 

per vehicle, with an average cost of $1,088 (McCormick, 

2003). 

While this study is illustrative of the benefi ts that might 

accrue from a diesel I&M program, there are a number 

of practical concerns with these programs. The most 

important is that EPA’s current MOBILE6.2 emissions 

inventory modeling software does not include any 

assumptions about high-emitting diesel vehicles, and 

it does not have any ability to quantify the benefi ts of a 

diesel I&M program. In addition, EPA has not issued 

guidance as to how a state might otherwise quantify the 

emissions reductions resulting from a diesel I&M program 

for purposes of developing a SIP for achieving federal 

air quality standards. Under these circumstances, it is 

unlikely that any state would be successful in arguing for 

SIP credit absent signifi cant new testing information.

As noted above, California has mandated OBD systems 

on new diesel vehicles beginning in the 2010 model 

year. Adoption of these regulations by other states would 

eventually allow the use of OBD to identify high emitters 

in a diesel I&M program, as in many current light-duty 

I&M programs. However, such a program would be 

unlikely to have a signifi cant impact prior to 2020. 
 Chapter 13 - Diesel Trucks and Buses 197

In addition to diesel OBD, there are other testing 

technologies under development that could potentially 

supplement opacity testing in a diesel I&M program, 

including the use of remote sensing devices (RSD) to 

measure smoke opacity and gaseous emissions from 

onroad diesel vehicles as they drive by a fi xed sensor. 

RSD technology is well-developed for light-duty gasoline 

vehicles and EPA has issued guidance concerning its use in 

light-duty vehicle I&M programs. However, RSD has only 

recently been demonstrated as a way to measure emissions 

from diesels—by the Massachusetts Bay Transportation 

Authority in Boston, Massachusetts, and in an EPA-funded 

project at the U.S.-Mexico border in Nogales, Arizona. 

It is more diffi cult to apply RSD testing to heavy-duty than 

to light-duty vehicles, due to the ubiquity of high-mounted 

exhaust stacks and a lack of uniformity in stack heights 

on these vehicles. In addition, as with opacity testing, 

the lack of EPA guidance on quantifying benefi ts from an 

RSD-based diesel I&M program would make it diffi cult 

for states to claim SIP credit for such a program at this 

time.

Idle Reduction

All diesel vehicles, of necessity, idle at some point during 

their typical daily duty cycle—for example, while sitting 

at a traffi c light. Unfortunately, however, some vehicle 

operators continue to idle their vehicles when it is not 

really necessary—examples include delivery trucks that 

idle while making deliveries or school buses that idle while 

picking up or dropping off students. Unnecessary idling 

wastes fuel and increases total daily emissions of NOx

and PM; often it also increases the exposure of sensitive 

populations to these pollutants. EPA estimates that idling 

Class 8 trucks use, on average, 0.82 gallons of diesel fuel 

per hour and produce 144 grams per hour of NOx emissions 

(EPA, 2002).

In order to reduce or eliminate unnecessary idling, 

approximately 26 states and cities have enacted laws that 

restrict the idling of diesel vehicles. Typically, these laws 

set a maximum allowable idling time of 2–15 minutes. 

Operators of vehicles found parked and idling longer than 

the limit can be fi ned (ATRI, 2004).

These laws usually provide an exemption for all idling in 

traffi c, as well as idling necessary to ensure safe operation 

of the vehicle—for example, to maintain the air pressure 

in the air brake system. Recognizing that starting diesel 

engines in extremely cold conditions can be diffi cult, these 

laws also often provide an exemption to allow additional 

idling below a specifi c ambient temperature. Finally, some 

idling restrictions also provide an exemption to maintain 

power for heating, cooling or auxiliary equipment. The 

Maricopa County, Arizona law allows additional idling to 

maintain bus passenger comfort when the temperature is 

above 75 degrees Fahrenheit (ATRI, 2004). 

One contentious issue associated with many current laws 

that restrict idling is their effect on operators of coach 

buses and the degree to which idling to maintain operator 

and passenger comfort should or should not be considered 

necessary idling. Because both the heating and air 

conditioning systems on buses are operated by the diesel 

engine, many operators keep their buses running while 

parked to maintain comfortable cabin temperatures for 

themselves and their passengers. 

Many vehicle operators have also complained about the 

lack of uniformity among idling laws in various locations. 

In early 2005, EPA announced an initiative to convene 

workgroups with affected parties to try to reach consensus 

on “model” idling restrictions. 

As with buses, cab climate control and electrical power 

on tractor-trailer trucks are usually supplied by the truck’s 

diesel engine. For this reason, long-haul truckers often 

keep their trucks idling all night as they rest in the sleeper 

cab. This idling is generally exempt from current idle 

restriction laws. For example, California law currently 

prohibits diesel vehicles from idling for more than fi ve 

minutes, but it exempts idling of trucks equipped with 

sleeper cabs. However, in October 2005 CARB considered 

a staff recommendation to extend the idle limit of fi ve 

minutes to all diesel vehicles, including sleeper-cab trucks, 

beginning in January 2008. To support this requirement, 

the proposed regulation would mandate non-programmable 

idle shutdown features (which could not be modifi ed by 

the user) on all new diesel trucks beginning in model year 

2008 (CARB, 2005c). CARB staff anticipates that truck 

manufacturers would respond by also installing auxiliary 

power units, or other methods to supply power to auxiliary 

loads, as standard equipment on trucks equipped with 

sleeper cabs. Methods of providing necessary electrical 

power for climate control, lighting and other amenities 

while reducing or eliminating the need for extended 

overnight idling are described as part of the discussion of 

diesel technology in Chapter 12. 

EPA testing has shown that use of these technologies can 

reduce total NOx emissions by 90–99 percent compared 

to idling the truck’s main engine (EPA, 2002). However, 

these methods require additional equipment to be installed 

either on the truck, at truck stops, or both.

EPA’s review of currently available devices indicates 

that on-board idle reduction technologies can cost 

between $500 and $8,500 per truck, with the auxiliary 

engine systems (which provide the greatest fl exibility) 

generally costing $5,000 or more. Services that provide 

cabin heating/cooling, electricity and other amenities at 

truck stops to preclude the need for on-board equipment 

generally charge between $0.50 and $1.50 per hour, 
198 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

depending on the services provided and the contracting 

arrangements that apply (EPA, 2005d).

States could encourage or mandate the use of these idle 

reduction technologies in the same way that they encourage 

or mandate vehicle retirement, engine repowering, retrofi t 

controls and fuel switching, as discussed above. EPA has 

issued guidance as to how a state can take credit for the 

benefi ts of an idle reduction program (EPA, 2004a).

EPA has funded several truck idle reduction demonstration 

projects, including electrifi cation projects at the Hunts 

Point produce market in New York City and at a truck stop 

in Gary, Indiana, as well as a program launched with the 

Electric Power Research Institute to subsidize the purchase 

and installation of on-board, battery-powered electric 

air conditioning and heating systems for trucks (EPA, 

2005d). EPA, the states of Oregon and Washington, and 

the non-profi t Climate Trust are funding the installation of 

electricity connections at 275 parking spaces at truck stops 

in those states; 18 similar connections have been installed 

in Wilton, New York on Interstate 87 with funding from 

the New York State Energy Research & Development 

Authority (Argus Air Daily, 2005).

In addition to reducing NOx emissions, EPA testing has 

shown that the use of technologies to avoid idling can 

reduce total fuel use by 0.8 gallons per hour or more 

(EPA, 2002). By eliminating only four hours of idling 

a day, a trucker could reduce his or her fuel costs by 

$2,000 per year or more,1 and pay for the installation of 

many idle reduction technologies in three years or less. 

Despite relatively short payback periods, adoption of 

these technologies could be impeded by a vehicle owner’s 

shortage of capital funds. In such cases, the development 

of a revolving loan fund could spur technology adoption 

(see Chapter 14, Nonroad Equipment, regarding the 

West Coast Collaborative revolving fund to fi nance idle 

reduction technologies on locomotives). 

Reducing Fuel Usage

As discussed above, there are a number of changes besides 

idle reduction that can be made to individual vehicles, 

and to the goods distribution system generally, that will 

reduce fuel usage from onroad heavy-duty diesel vehicles, 

particularly Class 8 tractor-trailer trucks. These include 

the use of lower rolling resistance tires, the maintenance of 

proper tire infl ation and the reduction of highway speeds. 

Additionally, EPA has developed a voluntary partnership 

program with the transportation industry, called the 

SmartWay Transport Partnership, to focus attention on 

these possibilities and their benefi ts (EPA, 2005e). 

A similar program could be adopted or expanded at a local 

1. Assuming $2.50 per gallon for diesel fuel, a fuel savings of 0.8 gallon 

per hour and 250 days per year of vehicle operation. 

level to improve the transportation system and reduce fuel 

usage and emissions. In contrast to the emissions retrofi t 

strategies discussed above, the approaches highlighted in 

the SmartWay program produce a fi nancial payback for 

vehicle operators in the form of reduced fuel purchases. 

They are therefore more likely to be adopted without 

public subsidies, particularly in times of high and rising 

fuel prices.

In addition, linkages could be made between some of 

these fuel-saving strategies and the emissions-focused 

retrofi ts discussed above (“Green Branding”). In this 

way, fuel savings could be used to offset some of the cost 

of adopting emissions reduction technologies, thereby 

enhancing voluntary buy-in and reducing the total public 

subsidy required to elicit participation. 

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200 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Standards and Highway Diesel Fuel Sulfur Control 

Requirements (EPA420-R-00-026), December, 2000. 

(2000b) 

U.S. Environmental Protection Agency (EPA). “Control 

of Air Pollution from New Motor Vehicles: HeavyDuty Engine and Vehicle Standards and Highway Diesel 

Fuel Sulfur Control Requirements; Final Rule,” Federal 

Register 66(12): 5002, January 18, 2001.

U.S. Environmental Protection Agency (EPA). Study of 

Exhaust Emissions from Idling Heavy-Duty Diesel Trucks 

and Commercially Available Idle-Reducing Devices

(EPA420-R-02-025), October 2002.

U.S. Environmental Protection Agency (EPA). Guidance 

for Quantifying and Using Long Duration Truck 

Idling Reductions in State Implementation Plans and 

Transportation Conformity (EPA420-B-04-001), January 

2004. (2004a)

U.S. Environmental Protection Agency (EPA). SmartWay 

Transport Partnership, A Glance at Clean Freight 

Strategies Reducing Highway Speed (EPA420-F-04-007), 

February 2004. (2004b)

U.S. Environmental Protection Agency (EPA). 2002 

National Emissions Inventory: Mobile Source Draft, June 

2005. www.epa.gov/ttn/chief/net/2002inventory.html. 

(2005a)

U.S. Environmental Protection Agency (EPA). Voluntary 

Diesel Retrofi t Program, 2004 Grants, accessed 

September 15, 2005, from: www.epa.gov/dieselretrofi t/

dieselgrants2004.htm. (2005b)

U.S. Environmental Protection Agency (EPA). Voluntary 

Diesel Retrofi t Program, accessed September 16, 2005, 

from: www.epa.gov/cleandiesel/index.htm#voluntary. 

(2005c)

U.S. Environmental Protection Agency (EPA). SmartWay 

Transport Partnership: Idling Reduction Technologies,

accessed October 4, 2005, from: www.epa.gov/otaq/

smartway/idlingtechnologies.htm. (2005d)

U.S. Environmental Protection Agency (EPA). SmartWay 

Transport Partnership, accessed October 4, 2005, from: 

www.epa.gov/otaq/smartway/swresources.htm. (2005e)

U.S. Environmental Protection Agency (EPA). “1970-2002 

Average Annual Emissions, All Criteria Pollutants,” 

National Emissions Inventory (NEI) Air Pollutant 

Emissions Trends Data, July 2005. www.epa.gov/ttn/

chief/trends/index.html. (2005f)

U.S. v. Caterpillar, Inc., no. 98-02544 (D. D.C. 1999). July 

1, 1999. www.epa.gov/compliance/resources/cases/civil/

caa/caterpilall.pdf.
202 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Nonroad motorized equipment comes in a wide variety 

of sizes and confi gurations. This category of emissions 

sources encompasses everything from lawn mowers and 

snowmobiles to construction equipment, ocean-going ships 

and locomotives. 

Smaller types of nonroad equipment—which generally 

fall into the category of either lawn and garden equipment 

(e.g., lawn mowers, handheld leaf blowers and edgers, 

etc.) or recreational equipment (e.g., snowmobiles, allterrain vehicles, small marine outboards, etc.)—are 

primarily powered by gasoline engines. Traditionally, 

exhaust emissions from these small engines have not been 

regulated as strictly as emissions from the larger gasoline 

engines used in cars and light trucks. For that reason, these 

pieces of equipment individually have very high emissions 

relative to the amount of fuel they consume. In addition, 

there are signifi cantly more of them than there are of the 

larger, heavy-duty diesel-powered nonroad equipment. As 

a group, small nonroad gasoline equipment contributes a 

signifi cant percentage of total volatile organic compound 

(VOC) emissions nationally, but is not a signifi cant source 

of the direct fi ne particulate matter (PM2.5) or PM2.5-

precursor emissions that are the focus of this report (EPA, 

2005b). Therefore, small nonroad gasoline equipment is 

not discussed in this chapter. 

With respect to direct PM2.5 and major PM2.5-precursor 

emissions, larger diesel-powered nonroad equipment is 

much more important. This category of sources, which 

encompasses primarily commercial farm and construction 

equipment, includes engines in a wide variety of sizes and 

confi gurations from as small as 20 horsepower to as large 

as 5,000 horsepower or more.

The major subcategories of nonroad diesel equipment 

include agricultural tractors and combines, airport 

ground-support equipment, construction and mining 

equipment (e.g., loaders, tractors, pavers, generators, 

compressors, etc.), commercial and industrial equipment 

(e.g., generators, compressors, refrigeration units, etc.) 

and logging equipment. In addition, rail locomotives and 

marine ships are generally included with these other types 

of nonroad equipment in emissions inventories. The larger 

marine ships generally have both very large engines that 

are used for propulsion and smaller auxiliary engines that 

Chapter 14

Nonroad Equipment
 Chapter 14 - Nonroad Equipment 203

are used to generate electricity and/or operate pumps onboard. 

Technically, aircraft are also considered nonroad 

equipment, but they are addressed in Chapter 16, Airports.

Regardless of size, the diesel engines used in agricultural, 

construction, industrial and some marine equipment are 

generally similar; they are also similar to the engines used 

in onroad diesel vehicles. The engines used in locomotives 

and some ships are signifi cantly different and are regulated 

differently by EPA. The propulsion engines in the largest 

ocean-going ships are unique and generally burn heavier 

residual fuels. EPA has separate emissions standards for 

locomotives and ships.

While agricultural equipment is concentrated in rural 

areas, other nonroad diesel engines contribute signifi cantly 

to urban air quality concerns. In 1999, 45 percent of 

PM emissions and 26 percent of nitrogen oxides (NOx) 

emissions from mobile sources in New York City came 

from construction equipment (EPA, 2005c). Likewise, 

marine emissions can be signifi cant in coastal areas. In 

2003, approximately 7.5 percent of all NOx emissions in 

Los Angeles came from ships (CARB, 2005a).

This chapter discusses the current and projected inventory 

of direct PM2.5 and PM2.5-precursor emissions from nonroad 

diesel equipment, the regulatory authority to address these 

emissions from new and existing engines, and the control 

strategies that state and local authorities can consider to 

reduce emissions from nonroad diesel equipment fl eets 

as they develop their State Implementation Plans (SIPs). 

Some of the strategies discussed involve the use of various 

diesel retrofi t technologies, which are described in Chapter 

12, Diesel Engine Technologies.

Sector Profi le

Most direct PM2.5 and PM2.5-precursor emissions from 

nonroad equipment come from the combustion of diesel 

fuel in diesel engines. Approximately 90 percent of the 

PM directly emitted by these vehicles is PM2.5. Some 

nonroad equipment is gasoline-powered, but it accounts 

for an insignifi cant portion of the direct PM2.5 and PM2.5-

precursor inventory (EPA, 2005b). PM2.5 from tire and 

brake wear in nonroad equipment is also insignifi cant.

The annual direct PM2.5 emissions from nonroad equipment 

are twice those from all onroad vehicles, including both 

heavy-duty trucks and light-duty cars (EPA, 2005b). This 

is 4 percent of the total direct PM2.5 inventory, including 

stationary sources. However, the hazardous nature of 

diesel exhaust and the proximity of diesel exhaust sources 

to sensitive populations magnifi es the health impact. 

Diesel exhaust contains over 40 substances listed by EPA 

as hazardous air pollutants, 15 of which have been listed 

by the International Agency for Research on Cancer as 

known, probable, or possible human carcinogens (CARB, 

1998). Many of these substances are adsorbed onto the 

particles that are emitted in diesel exhaust. For this reason, 

the California Air Resources Board (CARB) has formally 

designated diesel PM as a toxic air contaminant. 

Exhaust from nonroad diesels also accounts for about 

20 percent of all NOx emissions, including those from 

stationary and other mobile sources—in fact, NOx emitted 

by nonroad diesels amounts to about half that produced 

by onroad vehicles (EPA, 2005b). Therefore, nonroad 

diesel engines are an important source of PM2.5-precursor 

emissions. 

Nonroad equipment accounts for 2.5 percent of total annual 

sulfur dioxide (SO2) emissions nationally (EPA, 2005b). 

SO2 emissions from nonroad engines are higher than those 

from onroad vehicles because nonroad diesel fuel currently 

has signifi cantly more sulfur than gasoline or onroad 

diesel fuel. However, these nonroad SO2 emissions will be 

reduced dramatically beginning in 2007, when allowable 

fuel sulfur levels for nonroad diesel fuel will decline by 

over 80 percent (see below). Thus, efforts to reduce PM2.5

and PM2.5-precursor emissions from the nonroad diesel 

sector should focus on reducing exhaust emissions of both 

direct PM2.5 and NOx. 

Regulatory Authority

As discussed in Chapter 4, the Clean Air Act gives EPA 

primary authority to regulate emissions from new nonroad 

equipment. California has authority to adopt its own 

emissions standards for some, but not all, new nonroad 

equipment, as long as its standards are at least as stringent 

as the federal standards. Other states can adopt either the 

California or the federal standards. For some existing

Table 14.1 

Major Nonroad Equipment Populations

Equipment Type Population (x1000)

Diesel

Agricultural 3,208

Airport ground-support equipment 22

Commercial/industrial 10,456

Construction/mining 3,017

Logging equipment 330

Gasoline

Lawn and garden 108,460

Recreational 25,488

Source: EPA, 2004b
204 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

nonroad equipment, states can adopt California or federal 

standards, but not their own standards. Note that this 

stands in contrast to the Act’s approach to existing onroad 

vehicles, for which both states and local areas are free to 

set their own standards. At present, California standards 

for new heavy-duty nonroad engines largely track federal 

standards. This is also true for California’s onroad diesel 

rules, though not for California’s rules with regard to 

nonroad gasoline equipment (e.g., leaf blowers and marine 

pleasure craft outboard engines), which are stricter than 

federal requirements. California has begun to adopt 

mandatory retrofi t requirements for some categories of 

nonroad equipment.

That said, certain categories of nonroad equipment are fully 

preempted under §209(e) of the Clean Air Act, meaning 

that no state—including California—may set standards 

for this equipment. Section 209 preemption applies to new 

engines used in construction equipment or vehicles and 

new engines used in farm equipment or vehicles, provided 

the engines are smaller than 175 horsepower; it also applies 

to new locomotives or new engines used in locomotives. In 

addition, as discussed below, EPA regulates the emissions 

of NOx (but not of other pollutants) from large ocean-going 

vessels with an eye to international treaty negotiations. 

Generally speaking, EPA has three separate regulatory 

schemes for nonroad diesel engines: one for locomotive 

engines, one for marine engines and one for all other 

engines (agricultural, industrial, construction, etc.). Each 

of these categories of engines will be discussed separately. 

For regulatory purposes, nonroad engines are those 

used in mobile equipment that is not intended for use on 

public roadways. Therefore, the defi nition of “nonroad” 

is primarily based on mobility or portability. Despite the 

fact that it may be virtually identical to an engine used in a 

piece of mobile equipment, any diesel engine that will stay 

in the same place for 12 months or more—for example, to 

power a stationary generator or pump—is regulated as a 

stationary emissions source and is not discussed in this 

chapter (DieselNet, 2005).

Construction, Agricultural and Industrial 

Engines

The fi rst EPA emissions standards for new nonroad engines 

other than marine engines and locomotives were adopted 

in 1994. These Tier 1 standards were phased in for engines 

of different sizes starting as early as model year 1996. In 

1998, EPA fi nalized a rule that requires more stringent Tier 

2 and Tier 3 standards to be implemented for engines built 

between 2001 and 2008, and in 2004 the Agency fi nalized 

Tier 4 standards that will take effect between 2008 and 

2015 (EPA, 2004a, 2004f).

As with emissions standards for onroad truck and 

bus engines, emissions limits for nonroad engines are 

expressed in terms of mass per unit of work done by the 

engine—that is, grams per brake-horsepower hour (g/

bhp-hr), or grams per kilowatt hour (g/kWh). Unlike 

the onroad standards, however, the nonroad standards 

provide different numerical limits depending on engine 

size, with smaller engines allowed to have relatively 

higher emissions. For example, the Tier 1 PM limits for 

a 175–300 horsepower engine were 0.40 g/bhp-hr, while 

they were 0.75 g/bhp-hr for an engine smaller than 11 

horsepower. 

In addition, the Tier 1–3 nonroad limits were signifi cantly 

less strict than those in place for onroad engines at the 

same time. For example, a 250 horsepower engine 

installed in an onroad truck in 2000 would have had to 

meet a NOx standard of 4.0 g/bhp-hr and a PM standard 

of 0.10 g/bhp-hr; virtually the same engine installed in 

an agricultural tractor in the same year would have been 

allowed to emit 6.9 g/bhp-hr NOx and 0.40 g/bhp-hr PM. 

When fully implemented in 2016, the Tier 4 nonroad limits 

will introduce general parity between onroad and nonroad 

standards for all diesel engines other than the smallest 

and largest engines. Nonroad engines smaller than 75 

horsepower and some engines greater than 750 horsepower 

will still be allowed to emit signifi cantly more NOx and 

PM than onroad and other nonroad engines. 

EPA has separate limits for heavy-duty spark-ignition 

engines (primarily fueled by gasoline). Given the 

relatively small stock of heavy-duty nonroad equipment 

powered by such engines, these limits are not discussed 

here. 

Locomotives

EPA fi rst regulated emissions from locomotive engines 

in 2000. In that year, a set of three standards (Tiers 0–2) 

became effective, with the operative standard depending 

on the year the engine was produced. Tier 0 standards 

apply retroactively to any engine manufactured between 

1973 and 2001; Tier 1 applies to new locomotive engines 

produced from 2002 to 2004; and Tier 2 applies to new 

locomotive engines produced beginning in 2005 (EPA, 

2004f). 

Unlike other diesel engine standards, the locomotive 

standards provide two different numerical emissions limits 

based on two different test cycles that replicate the major 

modes of locomotive operation: line haul and switchyard. 

Line haul operation is characterized by signifi cant time 

at the highest engine power settings, while in switchyard 

operations the engine spends a signifi cantly greater 

amount of time at low power settings and at idle. The EPA 

Tier 0–2 regulations require that each engine meet both 

sets of numerical standards. 
 Chapter 14 - Nonroad Equipment 205

In 2003, EPA adopted Tier 1 NOx standards for new 

Category 3 marine engines. These standards take effect 

beginning in model year 2004. They are equivalent to 

the limits in Annex VI to the International Convention 

for the Prevention of Pollution from Ships (also known 

as the MARPOL Convention), which was negotiated 

internationally under the auspices of the International 

Maritime Organization (IMO). The Tier 1 NOx standards 

for Category 3 engines are 9.8–17 g/kWh, depending 

on engine speed; slower engines are allowed to emit 

more (DieselNet, 2005). PM and other pollutants are not 

regulated under either MARPOL Annex VI or the EPA 

Tier 1 standards. 

As with locomotive engines, EPA issued an Advanced 

Notice of Proposed Rulemaking in June 2004 indicating 

that it was considering Tier 3 standards for Category 1 and 

2 marine engines, to be implemented as early as model year 

2011. These proposed standards would seek to reduce both 

PM and NOx emissions by 90 percent or more compared 

to the Tier 2 standards and would bring Category 1 and 2 

marine engine emissions roughly in line with emissions 

from other nonroad engines under the nonroad Tier 4 rules 

(EPA, 2004a). 

To date, EPA has not proposed any tightening of the 

current Tier 1 emissions standards for Category 3 marine 

engines. However, the current administration, through 

the State Department, has supported MARPOL Annex VI 

and has indicated a desire to further tighten NOx standards 

and apply PM limits in future IMO negotiations (Argus, 

2005a). The international nature of ocean-going vessels 

complicates efforts to effectively regulate their emissions 

without international agreements.

As discussed above, regulation to limit emissions from 

nonroad diesel engines is a relatively new phenomenon: 

standards for these types of engines were fi rst introduced 

In addition, unlike other diesel emissions standards, the 

Tier 0–2 locomotive standards apply not only when the 

engine is fi rst produced, but also every time the engine 

is re-manufactured. In effect, this means that every 

locomotive engine built since 1973 must be upgraded to 

meet Tier 0 standards when it next has a major overhaul. 

It is estimated that upgrading an unregulated locomotive 

engine to Tier 0 standards reduces NOx emissions by 

approximately 30 percent, but produces no appreciable 

reduction in PM emissions. New engines built to comply 

with Tier 2 standards will have approximately 60 percent 

lower NOx and 40 percent lower PM emissions than 

unregulated engines (DieselNet, 2005). 

In June 2004, EPA issued an Advanced Notice of Proposed 

Rulemaking indicating that it was considering Tier 3 

locomotive engine standards. These standards would be 

implemented for new locomotive engines built as early as 

model year 2011 and would seek to reduce both PM and 

NOx emissions by 90 percent or more compared to the Tier 

2 standards. This would bring locomotive engine emissions 

roughly in line with emissions from onroad trucks under 

the 2007 rules and with emissions from other nonroad 

engines under the Tier 4 rules (EPA, 2004a).

Marine Engines

For regulatory purposes, marine engines are divided into 

three categories based on size (cylinder displacement). The 

smallest Category 1 engines are very similar to the diesel 

engines used in onroad trucks and nonroad land-based 

vehicles. These marine engines are used for propulsion 

power in personal and some small commercial vessels 

such as tugboats and other harbor craft. They may also 

be used as auxiliary engines in larger commercial vessels. 

Category 2 engines, which are usually larger than 1,000 

horsepower, are virtually identical to locomotive engines 

and are used for propulsion and auxiliary power in large 

commercial vessels.

The largest, Category 3 marine engines, are unique. 

Ranging in size from 3,000 to 100,000 horsepower, they 

are used for propulsion power in very large ocean-going 

vessels such as cruise ships, freighters and tankers. 

In 1999, EPA adopted Tier 2 emissions standards for new 

Category 1 and Category 2 marine engines. The Tier 2 

standards take effect between model years 2004 and 2007. 

These standards, which vary by engine size, set numerical 

limits that, for Category 1 engines, are similar to the Tier 2 

nonroad standards and, for Category 2 engines, are similar 

to the Tier 1 locomotive standards. This regulation also 

designates voluntary “blue sky” emissions standards to 

which engine manufacturers may choose to certify. A blue 

sky certifi ed marine engine has 40–50 percent lower NOx

and PM emissions than a Tier 2 engine (DieselNet, 2005). 

Table 14.2

Standards for Low Sulfur Diesel Fuel

Category Maximum Sulfur Limit (ppm)

2006 2007 2010 2012

Highway 15 15 15 15

Nonroad 3,000a 500 15 15

Marine 

Distillate/ 

Locomotive

3,000a 500 500 15

Marine 

Residual

20,000 20,000 20,000 20,000

a. 3,000 ppm is an approximate value representing uncontrolled 

emissions levels.

Source: Dieselnet, 2005
206 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

in 1994. The earliest regulation of nonroad diesel engines 

lagged behind the fi rst standards for PM emissions from 

onroad diesel engines by six years; standards for onroad 

diesels, meanwhile, had lagged behind the regulation of 

gasoline cars by over 15 years. Since nonroad equipment 

can have a useful life of 40 years or more, this means 

that the vast majority of nonroad equipment in use today 

was not subject to any emissions limits when it was 

manufactured. 

In addition, the turnover of nonroad diesel equipment tends 

to be very slow, so that even the more stringent current and 

future rules discussed above will not begin to have a major 

impact for many years. Based on normal fl eet turnover, 

EPA estimates that annual NOx and PM emissions from 

nonroad diesel engines will fall by only 10 percent and 

20 percent, respectively, through 2010. By comparison, 

expected NOx and PM reductions from the onroad heavyduty diesel fl eet over the same time period are expected 

to total 22 percent and 37 percent, respectively. Through 

2020, NOx and PM reductions for the nonroad fl eet are 

expected to reach 37 and 56 percent, respectively; this 

compares to anticipated emissions reductions of 77 and 84 

percent from the onroad fl eet over the same time period. 

(EPA, 2000; EPA, 2004g).

Fuel Quality

EPA has authority to regulate the quality of fuel and 

fuel additives used in vehicles based on health effects 

associated both with direct exposure to the fuel and with 

the effect of the fuel on the ability of vehicles to meet 

emissions standards. EPA began to regulate the sulfur 

content of onroad diesel fuel in 1994 when it limited 

onroad fuel sulfur content to a maximum of 500 parts per 

million (ppm). The sulfur content of fuel used in nonroad 

diesels was unregulated at that time: distillate fuels 

currently used in construction equipment, locomotives and 

many marine vessels typically have sulfur levels as high 

as 3,000 ppm. The sulfur content of the heavier residual 

oils used to power ocean-going ships can be even higher, 

as much as 50,000 ppm or more. 

To enable the use of advanced catalytic emissions 

controls, which will be required to meet the nonroad Tier 

4 standards and proposed Tier 3 locomotive and marine 

standards discussed above, EPA has imposed limits on the 

allowable level of sulfur in nonroad diesel fuel for the fi rst 

time. All nonroad diesel fuel will be limited to 500 ppm 

sulfur beginning in June 2007. Fuel sulfur limits will be 

reduced to 15 ppm for nonroad vehicles in 2010, and for 

locomotives and marine distillate fuels in 2012 (EPA, 

2004f). 

These sulfur limits do not apply to the residual fuels used 

in ocean-going ships, which remain unregulated in the 

U.S. IMO MARPOL Annex VI establishes a global cap 

of 45,000 ppm on the sulfur content of marine residual 

fuels. This treaty also includes a mechanism to establish 

a 15,000 ppm cap in specifi c Sulfur Emission Control 

Areas (SECA)—typically near coasts—where additional 

emissions reductions are considered critical. While the 

U.S. has not formally ratifi ed Annex VI, the administration 

has supported ratifi cation together with the designation of 

U.S. coastal waters as a SECA zone (Argus, 2005a). 

As discussed in Chapter 4, The Clean Air Act, if EPA 

has regulated a fuel characteristic or component, states 

other than California may not adopt either their own or 

California’s regulation—they must follow the federal 

regulation. The only exception to this is the situation in 

which the Administrator fi nds that state regulation is 

necessary for achieving the National Ambient Air Quality 

Standards (NAAQS). On the other hand, California may 

adopt its own fuel regulations.

Other Regulations: California

As noted previously, the Clean Air Act—subject to certain 

exceptions (e.g., locomotives)—allows California to set 

its own emissions standards for both new and existing 

nonroad equipment. However, California has, for the 

most part, adopted EPA regulations for new nonroad 

diesel equipment with only slight modifi cations (the same 

is true for California’s onroad diesel rules, although its 

nonroad gasoline rules—for equipment like leaf blowers 

and marine pleasure craft outboard engines—are stricter 

than federal requirements). California has begun to adopt 

mandatory retrofi t requirements for some categories of 

nonroad equipment. All of the California programs that 

are discussed in later sections of this chapter cover existing

vehicles.

California also has its own regulations on the quality of 

diesel fuel, both onroad and nonroad. Under the California 

rules, nonroad diesel fuel sold in California for other than 

locomotive or marine applications will be limited to 15 

ppm sulfur beginning in 2006, four years earlier than 

the nonroad diesel sold in the rest of the country (CARB, 

2004b). 

State Authority

States are confi ned to California standards or to federal 

standards for new nonroad engines, and they are limited to 

California standards for existing nonroad engines. In fact, 

even the authority to adopt California regulations for these 

sources is largely theoretical at this point, since California 

has just begun to adopt mandatory retrofi t requirements 

for specifi c types of nonroad equipment, beginning with 

portable engines. However, none of the limitations on 

the imposition of state and local standards prohibits the 

adoption of voluntary programs, or the inclusion of retrofi t 

requirements in government contracts for construction or 

other services.
 Chapter 14 - Nonroad Equipment 207

Emissions Control Opportunities

Many of the emissions reduction technologies that are and 

will be applied to new nonroad diesel engines to comply 

with current and future EPA regulations can be applied to 

existing engines and vehicles as well. There are three main 

approaches to reducing emissions from these vehicles: use 

a cleaner engine, use a cleaner fuel or add a retrofi t device. 

In many cases, changes to equipment, vehicles and/or 

operational practices that reduce total fuel usage can 

reduce total emissions and also save money. 

Use a Cleaner Engine

New nonroad diesel engines certifi ed to Tier 2 or Tier 3 

EPA standards produce 30–60 percent less NOx and PM 

than the unregulated engines built as recently as a few 

years ago. These reductions have come from changes 

in diesel engine design, most notably better control of 

lubrication oil, higher fuel injection pressures, and the 

addition of electronic fuel control. In some instances, 

particularly in the case of Tier 3 engines with electronic 

fuel control, emissions reductions have been accompanied 

by improved fuel effi ciency. Removing older engines from 

service and replacing them with new engines can therefore 

have a large positive emissions benefi t. 

For most older vehicles, it is more cost-effective to retire 

the vehicle itself. However, in some cases involving 

specialty equipment, where the engine represents a 

relatively small percentage of the vehicle’s total value, 

repowering an old vehicle with a new engine may be the 

better alternative. In particular, repowering has proved to 

be cost effective for Category 1 marine engines larger than 

600 horsepower because resulting improvements in fuel 

economy can partially offset the cost of a new engine. 

For some nonroad equipment, it may be possible to 

produce even larger emissions reductions by repowering 

with an onroad engine that is certifi ed to even lower 

standards than new nonroad engines. In limited cases it 

may also be possible to cost-effectively modify existing 

engines to incorporate more modern design elements and 

equipment—such as improved fuel injectors—that result 

in lower emissions. 

Use a Cleaner Fuel

Some alternative formulations of diesel fuel produce lower 

emissions of NOx and/or PM in existing engines than 

standard nonroad diesel fuel. The most common of these 

cleaner diesel fuels are described in Chapter 12, Diesel 

Engine Technologies.

Heavy-duty engines that operate on natural gas and 

therefore produce signifi cantly lower PM emissions than 

current diesel engines are also available for onroad trucks 

and buses. Natural gas engines have PM emissions 

essentially equivalent to the 2007 EPA PM standards for 

new onroad diesel engines. These natural gas engines 

are also certifi ed to produce 30–50 percent lower NOx

emissions than the current EPA NOx standards for new 

onroad diesels. 

While it is technically possible to modify existing diesel 

engines to operate on natural gas, it is generally preferable 

to use a purpose-built natural gas engine (ICCT, 2005).

Whether using a purpose-built or retrofi t engine, the 

vehicle fuel system must also be modifi ed extensively to 

store high-pressure gaseous or low-temperature liquefi ed 

natural gas fuel in lieu of liquid diesel fuel; in addition, 

this approach requires that high-pressure natural gas 

fueling stations be available. This means that conversion 

to natural gas is most appropriate for fl eet vehicles that are 

centrally fueled at a fi xed site and that operate within a 

limited geographic area. 

To date, there have been very few applications of natural 

gas engines to nonroad equipment. This is at least partially 

due to diffi culty in developing an appropriate fueling 

infrastructure. Unlike onroad fl eet vehicles that often 

travel to a centralized site for fueling, most construction 

equipment is regularly fueled at the construction site using 

mobile fueling equipment. 

Nonetheless, there may be targeted opportunities to 

utilize natural gas fuel in specifi c types of equipment. The 

West Coast Collaborative and South Coast Air Quality 

Management District in California have provided $2.2 

million to repower an existing locomotive with a natural 

gas engine and a liquefi ed natural gas fuel system (West 

Coast Collaborative, 2005c). This locomotive will be 

used to offset existing diesel truck traffi c. The Port of Los 

Angeles has also recently announced a goal to shift from 

diesel power to the use of natural gas engines for nonroad 

cargo-handling equipment at the port (Port of Los Angeles, 

2005).

In the category of cleaner fuels, electricity could also 

potentially play a role for some types of nonroad 

equipment. Depending on the fuel used for electricity 

generation, net NOx reductions of 40–80 percent can be 

achieved by converting a nonroad vehicle from diesel 

to electric power (EPA 2004c, DieselNet, 2005). While 

the dirtiest coal- and oil-burning power plants could 

actually produce greater PM emissions than nonroad 

diesel equipment, the actual grid mix in many parts of 

the country would produce net PM reductions of 25–95 

percent (EPA 1998, DieselNet, 2005). In either case, the 

localized air quality benefi ts are even greater, since all 

electric motors produce zero PM and NOx emissions at the 

point of use. 

Unlike onroad vehicles, which typically travel long 
208 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

distances in a day, many pieces of nonroad equipment 

are essentially stationary or operate within a very limited 

geographic area for a relatively long period of time. The 

range limitations associated with using batteries to power 

mobile electric vehicles may therefore not be an issue in 

the case of nonroad equipment. Where such equipment is 

essentially stationary, the necessary electric power can be 

pulled directly from the electric grid without the need for 

onboard batteries and periodic charging.

As discussed further in subsequent sections of this 

chapter and in Chapters 16 and 17, some specifi c potential 

applications of electric power to replace diesel fuel in 

nonroad engines include: hybrid-electric locomotive yard 

switchers; electrifi cation of forklifts, cranes and other 

material-handling equipment in ports and cargo terminals; 

electrifi cation of construction cranes; gate electrifi cation 

at airports; and the use of land-side electric power for 

auxiliary loads when ships are docked in port (cold 

ironing).

The use of reduced-sulfur onroad diesel fuel in nonroad 

equipment between now and 2010 can also directly reduce 

PM emissions from these vehicles, while also making 

the retrofi t of after-treatment PM control technologies 

more effective. After 2010, nonroad diesel fuel will be 

required to have the same low-sulfur level as onroad fuel 

(low-sulfur locomotive and marine distillate fuel will be 

available somewhat later, in 2012). 

Add a Retrofi t Device

As described in Chapter 12, Diesel Engine Technologies, 

some retrofi t technologies can be installed on existing 

diesel vehicles to reduce emissions. Most of these are 

“after-treatment” devices that install in the exhaust system; 

they clean up the exhaust after it has left the engine. Most 

of these technologies rely on some kind of catalytic process 

and can reduce either PM or NOx, but not both at the same 

time. However, different technologies can be combined 

into a single commercial product to produce simultaneous 

NOx and PM reductions. 

The category of retrofi t devices includes closed crankcase 

and crankcase fi lter systems that control crankcase vent 

emissions. These technologies are not currently included 

in EPA engine emissions limits (but will be included 

beginning with the 2011 model year). Testing on a 1998 

onroad diesel engine showed that PM emissions from the 

crankcase vent totaled 16–23 percent of the PM emissions 

coming from the tail pipe (RTI, 2003). 

The three main options for reducing emissions from diesel 

vehicles are not mutually exclusive. Some retrofi t devices 

work better in conjunction with, or even require the use 

of, an alternative diesel fuel. Some commercial products 

combine engine modifi cations with retrofi t devices, while 

engine repowering can always be combined with retrofi ts 

to reduce emissions even further. 

Fuel Economy Improvements

As discussed in Chapter 12, the fuel economy of highway 

trucks is dramatically affected by the aerodynamics of 

the vehicle and the rolling resistance of its tires. This is 

not the case for most nonroad equipment, which operates 

at relatively low speeds or is essentially stationary. 

Opportunities to reduce fuel use through vehicle design 

changes that are unrelated to the engine are therefore much 

more limited for nonroad equipment. 

Some new nonroad engines are both cleaner and more 

fuel effi cient than older engines, so that repowering to 

reduce emissions can provide additional benefi ts from 

fuel savings. In addition, some nonroad sectors may 

provide opportunities for signifi cant fuel savings based 

on operational changes. In particular, as discussed 

below, reduction of locomotive idling and cold ironing of 

marine vessels in port can result in signifi cant emissions 

reductions based on reduced diesel fuel usage. The 

agricultural sector may also provide opportunities for 

fuel savings and emission reductions based on changes in 

farming practices. 

State and Local Policy Measures

Programs that encourage or mandate the retirement or 

replacement of older diesel equipment, the use of cleaner 

fuels or electrifi cation, or the implementation of diesel 

retrofi ts provide the most signifi cant opportunity for states 

to control and reduce PM and NOx emissions from nonroad 

diesel fl eets. In fact, given the lag in nonroad emissions 

regulation and the slower turnover of these fl eets, nonroad 

equipment is an even better target for these types of 

programs than onroad diesel vehicles. Whether voluntary 

or mandatory, the common focus of these programs is 

on the application of new technology to existing diesel 

equipment. Programs that result in reduced fuel usage will 

also reduce PM and NOx emissions.

Voluntary Retrofi t Programs

Replacement of vehicles and engines, use of alternative 

fuels, and installation of retrofi t devices can be expensive. 

In general, the larger the engine, the larger and more 

costly the device. Replacement engines for construction 

equipment can cost $30,000 or more installed and Category 

1 marine engines can cost $100,000 or more (TCEQ, 

2004). Given this expense, voluntary emissions reduction 

programs are seldom effective without a funding source. 

Programs to promote emissions reductions from existing 

engines can take many forms, including the use of tax 

policy or rebates to offset the cost of implementing specifi c 
 Chapter 14 - Nonroad Equipment 209

measures. The most common programs for heavy-duty 

diesel vehicles are grant programs. These programs 

are usually competitive and are often evaluated for costeffectiveness (as measured in terms of dollar cost per ton 

reduction), such that funding is limited to only the most 

cost-effective projects or to those projects that achieve a 

specifi ed minimum level of cost-effectiveness. 

These programs generally provide a grant equal to the 

incremental cost of the action taken to reduce emissions. A 

grant program can fund early vehicle retirement/scrappage, 

engine repowering, fuel switching/electrifi cation, engine 

modifi cation and vehicle retrofi ts. 

The two largest grant programs of this type currently 

operating are California’s Carl Moyer Memorial Air 

Quality Standards Program (Carl Moyer) and the Texas 

Emissions Reduction Program (TERP). Since its 

inception in 1998, Carl Moyer has provided $184 million 

in grant funding for various emissions reduction projects 

throughout California (CARB, 2003). Approximately 30 

percent of these funds went to projects to reduce emissions 

from nonroad diesel equipment, including marine vessels, 

construction equipment, forklifts and locomotives (CARB, 

2005b).

Since 2001, TERP has provided $82 million in grants to 

replace 98 locomotives and retrofi t six yard switchers; 

$11 million to repower 89 and retrofi t six marine 

engines; and $14 million to replace or repower over 250 

pieces of construction equipment, including forklifts, 

cranes, tractors, loaders, excavators, bulldozers and 

air compressors in the 41 Texas counties designated as 

nonattainment areas (TCEQ, 2004). 

Both Carl Moyer and TERP make project awards based 

on a minimum level of cost-effectiveness and both are 

designed primarily to reduce NOx emissions, with a 

secondary focus on PM. 

EPA has also been making demonstration grants under 

its National Clean Diesel Campaign. The most recent 

grants were announced in February 2005, with a total of 

$1.6 million going to 18 projects across the country. The 

nonroad projects included retrofi ts of commuter rail 

locomotives, construction vehicles, agricultural equipment, 

rubber-tired gantry cranes and port straddle carriers. The 

EPA grant program requires local matching funds (EPA, 

2005d).

Over the last four years the Puget Sound Clean Air Agency 

has also sponsored and funded approximately 3,000 

retrofi ts of both onroad vehicles and nonroad equipment, 

including construction and port material-handling 

equipment. Its Diesel Solutions program is voluntary and 

incentive-based (Puget Sound CAA, 2005). The agency 

also helped to fund emissions testing of onroad low-sulfur 

fuel for the Washington State Ferry System, the largest 

ferry fl eet in the U.S. This testing showed that the use of 

current onroad fuel in the ferries reduced PM emissions 

by approximately 50 percent. Puget Sound subsequently 

switched all of its ferries to onroad fuel (McLerran, 2005).

Funding for clean air grant programs can come from 

a number of sources. See Chapter 13, Diesel Trucks 

and Buses, for a more detailed description of funding 

mechanisms.

Although some strategies have a relatively short payback 

period because of fuel savings, a vehicle owner’s shortage 

of capital funds can impede their adoption. In such cases, 

a revolving loan fund can spur technology adoption. Such 

a fund typically provides low-interest loans specifi cally 

for the purchase and installation of qualifying emissions 

reduction technologies. As the original recipients repay 

their loans, the funds are used to make additional loans. 

In 2005, the West Coast Collaborative developed such a 

fund to fi nance idle reduction technologies on locomotives 

operating on the west coast. This fund was established 

with $150,000 from EPA and $450,000 from the Climate 

Trust (West Coast Collaborative, 2005a). 

Mandatory Retrofi t Programs

States other than California are limited to California 

standards for existing nonroad equipment. 

In 2004, CARB adopted mandatory retrofi t requirements 

for portable diesel engines used in California in 

agricultural pumps, airport ground-support equipment, 

oil drilling rigs, portable generators and other nonroad 

equipment. The rule requires stepped-up reductions in PM 

emissions from these engines, with a 95 percent reduction 

to be achieved by 2020 (CARB, 2005). These are the fi rst 

mandatory retrofi t requirements California has adopted 

for any type of nonroad diesel engines, although CARB 

is evaluating a similar program for nonroad construction 

equipment.

Note that broad mandatory retrofi t requirements are 

harder to impose on privately-owned nonroad equipment 

than on privately-owned onroad vehicles, in part for 

practical reasons, because—unlike onroad vehicles that 

use public roadways—nonroad equipment is usually 

not required to be registered with the state. One of the 

reasons that California was able to impose mandatory 

retrofi t requirements for portable engines is that owners of 

these engines have been required for a number of years to 

register them with the state.

Government Contracting

While no state other than California has directly mandated 

the retrofi t of nonroad diesel equipment, a number of 
210 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

emissions standards. The Port is also requiring that all 

equipment burn ultra-low-sulfur diesel fuel. This multiyear project is expected to consume 3–5 million gallons of 

diesel fuel per year (McLerran, 2005). 

While experience has shown that the extension of 

voluntary government actions to the private sector is 

usually limited absent some direct economic incentive, 

meaningful results may still be achieved if the affected 

government sector is large enough. For example, given the 

large volume of publicly-funded construction in New York 

City—particularly in the context of the current downtown 

rebuilding effort—Local Law 77 is clearly intended to 

spur changes in the city’s entire construction sector and to 

mitigate the direct effect of rebuilding activities on nearby 

sensitive populations. This is a plausible objective, since 

contractors presumably use the same equipment on both 

public and private projects.

State and local agencies also often own and operate 

a signifi cant amount of nonroad equipment directly. 

Administrative policies that require retrofi ts, retirement/

repowering or fuel switching for these fl eets can 

complement similar policies for contracted equipment.

Inspection and Maintenance

Chapters 13 and 15 of this report discuss state-mandated 

inspection and maintenance programs (I&M) for onroad 

vehicles. These programs are generally designed to 

identify individual, high-emitting vehicles and require 

vehicle owners to repair them. As discussed in Chapters 

13 and 15, I&M is much more common in the U.S. for 

cars and light trucks than for heavy-duty diesel trucks 

and buses. One reason for this is that there are fewer 

well-developed tools for identifying high-emitting diesel 

vehicles than there are for identifying high-emitting 

gasoline vehicles. The development of heavy-duty I&M 

programs is further hampered by the fact that current EPA 

inventory models have no facility to give states credit for 

any emissions reductions that might result.

Developing effective I&M programs for nonroad diesel 

equipment is even more challenging than developing such 

programs for onroad diesel vehicles for three additional 

reasons: (1) there are usually no state registration 

requirements for nonroad equipment, (2) such equipment 

operates on private property rather than on public road 

ways and (3) since most nonroad equipment currently has 

an unregulated engine, it is less clear what would constitute 

a high emitter. 

No I&M programs for nonroad diesel equipment exist in 

the U.S. at this time. In 2005, however, CARB entered 

into a voluntary agreement with the BNSF Railway 

Company and the Union Pacifi c Railroad Company 

to reduce PM emissions in California rail yards. This 

states and localities have begun—through construction 

contracting—to indirectly mandate the retrofi t or 

replacement of nonroad diesel engines in specifi c types 

of fl eets, primarily construction equipment. While the 

nonroad equipment used in government contracting 

generally makes up only a small percentage of all nonroad 

equipment used in a locality, the appeal of indirect 

mandates imposed through government contracting 

policies is that they are allowed by the Clean Air Act for 

all states and local areas, they are usually relatively easy to 

implement, and they may help to build an experience base 

and a commercial market for retrofi t products and services 

that can later be extended to non-government controlled 

fl eets. 

In 2003, for example, the New York City Council adopted 

Local Law 77, which mandates the use of ultra-low-sulfur 

diesel fuel and requires retrofi ts for all diesel-powered 

construction equipment greater than 50 horsepower used 

on all publicly funded construction projects in New York 

City. The requirements were phased in between June 2004 

and December 2005, depending on the location and size 

of the project (New York City Department of Design & 

Construction, 2004).

Local Law 77 requires the use of “best available 

technology” to reduce PM emissions to the greatest extent 

possible. Under the implementing regulations developed 

by the New York City Department of Environmental 

Protection, contractors must install an EPA- or CARBverifi ed diesel particulate fi lter on each affected piece of 

equipment unless they can demonstrate that these devices 

are not technically feasible. If so, they can install a diesel 

oxidation catalyst or use emulsifi ed diesel fuel. (See 

Chapter 12 for details on these technologies.) 

The Illinois Department of Transportation took a similar 

approach for the rebuilding of the Dan Ryan Expressway 

through Chicago. Under the Illinois Clean Air 

Construction Initiative, the Department is mandating the 

use of cleaner fuels and retrofi ts for all diesel construction 

equipment over 50 horsepower used on the project. All 

equipment will be required to use, at a minimum, highway 

diesel fuel, which is lower in sulfur than nonroad diesel 

fuel. Some equipment will be mandated to use ultralow-sulfur diesel fuel and 25–30 pieces of equipment are 

expected to be retrofi tted with emissions reduction devices 

(Burke, 2005). The Department will also impose limits on 

construction vehicle idling and parking and will implement 

dust control measures.

Requirements adopted by the Port of Seattle for the 

construction of a new runway at Seattle’s Sea-Tac airport 

provide another example of this approach. In its contract 

specifi cations, the Port required that all construction 

equipment and haul trucks used for the project be latemodel equipment certifi ed to the most recent EPA 
 Chapter 14 - Nonroad Equipment 211

agreement requires the railroads to conduct annual opacity 

tests on every locomotive and to commit to repairing 

those locomotives that fail the test within 96 hours. These 

opacity tests are similar to the tests used in current I&M 

programs for onroad diesel vehicles. The agreement also 

requires the railroads to implement a pilot program to use 

remote sensing technology to measure emissions from inuse locomotives. While voluntary, this agreement includes 

monetary penalties for failure to implement its various 

requirements (CARB, 2005c). 

The California program could be considered a fi rst step 

toward developing I&M programs for nonroad equipment. 

However, EPA’s current nonroad emissions inventory 

modeling software does not include any assumptions about 

high-emitting nonroad equipment and does not have any 

facility to quantify the benefi ts of a nonroad diesel I&M 

program that uses either opacity testing or remote sensing. 

In addition, EPA has not issued guidance as to how a 

state might otherwise quantify the emissions reductions 

that result from such a program under its SIP. Thus, it is 

unlikely that any state would be successful in arguing for 

SIP credit, absent signifi cant new information based on 

testing.

Locomotive Idle Reduction

Chapter 13, Diesel Trucks and Buses, discusses idling 

restriction policies in the context of onroad diesel 

vehicles. These policies generally do not extend to 

nonroad diesel equipment for two reasons: (1) since this 

equipment operates on private property rather than public 

roadways, identifying idling vehicles and enforcing idling 

restrictions is more diffi cult and (2) the nature of the duty 

cycle can make the distinction between “necessary” and 

“unnecessary” idling more diffi cult to determine on many 

pieces of nonroad equipment.

Nonetheless, there are some distinct types of nonroad 

equipment that are known to idle excessively, particularly 

switcher yard locomotives. In some cases these 

locomotives are allowed to idle for long periods of time 

to maintain engine oil and coolant temperatures; in other 

cases, they are left to idle to provide a relatively small 

amount of electrical power for auxiliary equipment. They 

are often left to idle primarily because of the operator’s 

perception that it is easier to idle than to shut down and 

restart. Argonne National Laboratory estimates that a 

typical switcher yard locomotive idles up to 75 percent of 

the time and that idling consumes 27 percent of the total 

fuel used (Argonne, 2005). 

As discussed in Chapter 12, Diesel Engine Technologies, 

a number of alternative systems can be installed to 

provide the necessary electrical power for auxiliary loads 

on locomotives; in addition, systems exist that monitor 

various engine parameters and automatically shut down 

the engine when idling is unnecessary, restarting the 

engine as required. EPA’s review of currently available 

devices indicates that these idle reduction systems cost 

between $4,000 and $35,000 to install on a locomotive, 

depending on the type of device used. Given the amount 

of fuel that can be saved by reducing or eliminating idling, 

many of these systems have payback periods of six to 20 

months (Gaines, 2005). 

States and local areas can encourage or mandate the use 

of these technologies in the same way that they encourage 

or mandate vehicle retirement, engine repowering, retrofi ts 

and fuel switching, as discussed above. EPA has issued 

guidance concerning how a state can take credit for the 

benefi ts of an idle reduction program (EPA, 2004e).

In 2003, EPA awarded the City of Chicago a grant to 

evaluate emissions, noise reductions and fuel savings 

available to a Class 1 railroad through the use of idle 

reduction technology (EPA, 2004d). The West Coast 

Collaborative has recently provided grant funding to 

several projects designed to reduce or mitigate the effects 

of locomotive idling. In addition to the revolving loan 

fund approach discussed above, it has funded a project 

to use stationary source emissions control equipment 

to capture and treat the exhaust from idling locomotives 

undergoing repairs in a maintenance facility (West Coast 

Collaborative, 2005b). 

The Puget Sound Clean Air Agency has also provided a 

grant of $50,000 to Tacoma Rail to install idle reduction 

technology on two locomotives. In addition, Tacoma 

Rail has installed improved fuel injectors on these units 

to further reduce both emissions and fuel use (McLerran, 

2005).

The TERP program in Texas has provided funding 

for the purchase of nine “Green Goat” hybrid-electric 

locomotives to be used by two railroads and a chemical 

company in Texas. As discussed in Chapter 12, these 

units can signifi cantly reduce diesel fuel use and emissions 

from typical switcher yard operations compared to the use 

of a typical locomotive. In addition, Union Pacifi c has 

announced that it will add a total of 111 hybrid locomotives 

to its Texas operations over the next two years (Argus, 

2005b).

The voluntary agreement between CARB and several 

California railroads to reduce PM emissions in rail yards 

requires that all locomotives operated by the railroads be 

equipped with “automatic idling reduction devices” by 

June 2008 (CARB, 2005c). 

Nonroad Diesel Fuel

At approximately 3,000 ppm, the current sulfur content 

of nonroad diesel fuel impedes the use of effective retrofi t 
212 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

emissions controls on nonroad engines. In general, sulfur 

negatively affects the catalytic processes used to reduce 

PM emissions; diesel oxidation catalysts do not work well 

if fuel sulfur is greater than 500 ppm, and the even more 

effective diesel particulate fi lters require fuel with no more 

than 50 ppm sulfur (see Chapter 12). 

While EPA regulations will eventually require nonroad 

diesel sulfur reductions, the implementation dates for 

nonroad diesel fuel lag behind those for onroad fuel. 

Beginning in June 2007, when nonroad diesel will be 

required to have no more than 500 ppm sulfur, diesel 

oxidation catalyst retrofi ts will become practical on a 

wide range of nonroad equipment. Retrofi ts with the more 

effective diesel particulate fi lters will not be possible until 

nonroad diesel fuel sulfur is reduced below 50 ppm, which 

will occur in 2010 for most nonroad equipment under 

current EPA rules and in 2012 for locomotives and marine 

distillate fuels. Retrofi t programs for nonroad equipment 

will not be effective prior to these dates without either 

voluntary or mandatory use of onroad diesel fuel in the 

retrofi t nonroad equipment. For this reason, both New 

York City’s Local Law 77 and the Illinois Department of 

Transportation’s Clean Construction initiative include 

mandates for the early adoption of reduced sulfur fuels in 

the affected construction equipment. 

California is mandating that all nonroad diesel fuel sold in 

the state for other than locomotive and marine applications 

have no more than 15 ppm sulfur beginning in 2006—four 

years ahead of EPA mandates. While other states can 

implement similar requirements, such an action would 

require a fi nding by EPA that this would be necessary in 

order for the state to achieve federal air quality standards. 

Given the very high sulfur content of the residual fuel 

oil used to power ocean-going ships, very few retrofi t 

technologies will be effective on the Category 3 marine 

engines used for propulsion in these vessels. A switch to 

distillate fuels for these vessels would reduce PM and SO2

emissions and open up greater opportunities for retrofi ts. 

However, this would require modifi cations to the fuel 

systems on these engines and would dramatically increase 

fuel costs for vessel owners. 

A more practical approach would be a requirement to 

use reduced sulfur onroad or nonroad diesel fuel in the 

auxiliary engines that provide power while vessels are 

docked in port. For example, the Port of San Francisco is 

providing monetary incentives to offset the cost to cruise 

ship operators of using lower sulfur fuels while ships are 

docked at the port. EPA provided $100,000 toward the 

program through the West Coast Collaborative; other 

project partners are providing $141,000 in matching funds 

(West Coast Collaborative, 2005d). 

The Washington State Ferry System operates all of its 

vessels with onroad diesel fuel to reduce PM emissions and 

is piloting the use of ultra-low-sulfur diesel and biodiesel 

in selected ferries (McLerran, 2005).

Marine Programs

Many marine vessels operate auxiliary engines while 

in port to power their “hotel loads”—that is, onboard 

electrical equipment and pumps. For certain types of ships, 

especially cruise ships, refrigerated cargo vessels and 

some tankers, the loads being supplied can be signifi cant: 

anywhere from 600 to 7,000 kilowatts. In addition, some 

types of vessels spend signifi cant amounts of time in 

port; cruise ships typically spend 12–24 hours at the pier 

at the beginning and end of each trip while exchanging 

passengers. Some cargo vessels take can take 30–100 

hours or more to unload (Port of Long Beach, 2004).

The combination of high onboard power demand and long 

port calls results in signifi cant in-port exhaust emissions 

from the auxiliary engines on these ships. For example, an 

analysis of port calls at the Port of Long Beach in southern 

California determined that a single ship that regularly calls 

at the port produces over 85 tons of NOx, 9 tons of PM and 

79 tons of SOx annually while docked (Port of Long Beach, 

2004). Given that most major ports are in or near urban 

areas, these emissions can signifi cantly impact sensitive 

populations. 

One approach to reducing these emissions is to provide 

electrical power from the land-side electrical grid to supply 

in-port hotel loads instead of using onboard auxiliary 

diesel engines. The Navy pioneered this approach, which 

is called cold ironing. 

Cold ironing requires signifi cant modifi cations to both the 

affected ships and the land-side infrastructure. The fi rst 

cold ironing project in the U.S. was completed in 2001 in 

Juneau, Alaska. It involved the installation of necessary 

shore-side equipment and the retrofi t of four cruise ships 

owned by Princess Cruises to accept shore power during 

port calls (Port of Long Beach, 2004). Installing the 

shore-side equipment cost $4.7 million and retrofi tting the 

ships cost an average of $500,000 per vessel (Port of Long 

Beach, 2004). Princess Cruises is also participating in a 

shore power project at the Port of Seattle. This project is 

expected to reduce annual PM and NOx emissions within 

the port by 2 tons and 14 tons, respectively (McLerran, 

2005). 

Unfortunately, given the low cost of marine distillate fuels, 

the typical cost of electricity supplied from the land-side 

grid is slightly higher than the cost of fuel for onboard 

electricity generation. 

Given the costs involved, cold ironing is not appropriate 

for every ship. Nonetheless, the air quality benefi ts of this 
 Chapter 14 - Nonroad Equipment 213

approach can be signifi cant, and it can be cost-effective for 

ships with a signifi cant hotel load and a large number of 

annual port calls, each with a long duration. For example, 

the Long Beach study showed that the use of shore power 

to supply hotel loads to only three ships could reduce 

annual in-port emissions by almost 500 tons, at a cost of 

$11,000 per ton or less (Port of Long Beach, 2004).

The Port of Los Angeles has developed specifi cations for 

both the ship-side and shore-side equipment necessary 

for cold ironing, which it calls Alternative Marine Power 

(AMP). In June 2004, the port opened the fi rst U.S. 

container berth equipped to provide shore power (Berth 

100 at the China Shipping Terminal); two months later it 

hosted the fi rst ship capable of accepting the power (the 

NYK Atlas). The port has plans to install AMP equipment 

at additional terminals (Port of Los Angeles, 2005).

Other actions that can be taken to reduce ship emissions in 

and around ports include the use of lower sulfur diesel fuel 

in auxiliary engines while in port, as discussed above, and 

efforts to reduce ship speeds near the coast. 

Because ships that operate at lower speeds 

have lower emissions, both the Port of Long 

Beach and the Port of Los Angeles fund a 

Voluntary Commercial Ship Speed Reduction

Program, which urges vessels to travel at or below 12 

knots within 20 miles of the coast. The ports estimate that 

nearly 70 percent of shipping lines currently calling at the 

ports participate in the program and that NOx emissions 

from ships have been reduced by over 1 ton per day (Port 

of Los Angeles, 2005a).

The Washington State Ferry system has also reduced 

operating speeds to reduce fuel usage, in addition to 

installing improved fuel injectors on its vessels (McLerran, 

2005).

Operational Changes

Besides changes to equipment and fuels, some nonroad 

sectors may present good opportunities for emissions 

reductions through changes to infrastructure or operational 

procedures. These types of changes provide indirect PM 

and NOx reductions by reducing total fuel usage in the 

nonroad sector. 

For example, the Eastern Washington Farmers Diesel 

Emissions Reduction Program will offer cash incentives 

for farmers in six Washington counties to convert over 

16,000 acres of crop land from the use of traditional 

tillage practices to no till/direct seeding. By eliminating 

several traditional operations prior to seeding, the switch 

will allow farmers to use their tractors and other nonroad 

diesel agricultural equipment less. No till/direct seeding is 

currently practiced by approximately 50 percent of farmers 

in the Midwest, but by only 10 percent of farmers in 

Washington. Project sponsors expect that the conversion 

will reduce total diesel fuel use on the affected farms by 

over 50,000 gallons per year and result in annual NOx and 

PM reductions of 100 tons and 7 tons, respectively (West 

Coast Collaborative, 2005e).

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environment/airquality/Emissions.html. 

Port of Los Angeles. “Port of Los Angeles Announces 

Shift toward Air Quality Improvement Initiatives Powered 

by Natural Gas, Electricity, and Alternative Fuels,” Port of 

Los Angeles Press Release, October 12, 2005.

Port of Los Angeles. “Vessel Speed Reduction Program 

Eliminates 100 Tons of Emissions from Air in Three 

Months,” Port of Los Angeles Press Release, August 17, 

2005. (2005a)

Port of Los Angeles. Environment, Air Quality 

Programs, accessed September 10, 2005, from: www.

portofl osangeles.org/environment_aqp.htm. (2005b)

Puget Sound Clean Air Agency (Puget Sound CAA). 

Diesel Solutions, accessed October 1, 2005, from: www.

pscleanair.org/dieselsolutions/ds-overview.shtml.

Research Triangle Institute (RTI) and Southwest Research 

Institute. Environmental Technology Verifi cation Test 

Report of Mobile Source Emissions Control Devices: 

Donaldson Company, Inc. Series 6000 Diesel Oxidation 

Catalyst Muffl er and SpiracleTM Closed Crankcase 

Filtration System, September 30, 2003. www.epa.gov/etv/

pdfs/vrvs/05_vr_6000.pdf.

Texas Commission on Environmental Quality (TCEQ). 

Texas Emissions Reduction Plan (Biennial Report to the 

Texas Legislature; SFR-079/04, 2004), December 2004.

U.S. Environmental Protection Agency (EPA). Emission 

Standards Reference Guide for Heavy Duty and Nonroad 

Engines (EPA420-F-97-014), September 1997.

U.S. Environmental Protection Agency (EPA). “Chapter 

1: External Combustion Sources,” AP-42, Fifth Edition, 

Volume I, 1998. www.epa.gov/ttn/chief/ap42/ch13/index.

html.

U.S. Environmental Protection Agency (EPA). Regulatory 

Impact Analysis Heavy-Duty Engine and Vehicle 

Standards and Highway Diesel Fuel Sulfur Control 

Requirements (EPA420-R-00-026), December 2000.
 Chapter 14 - Nonroad Equipment 215

U.S. Environmental Protection Agency (EPA). Reducing 

Air Pollution from Nonroad Engines, April 2003. www.

epa.gov/otaq/cleaner-nonroad/f03011.pdf.

U.S. Environmental Protection Agency (EPA). “Control of 

Emissions of Air Pollution from New Locomotive Engines 

and New Marine Compression Ignition Engines Less than 

30 Liters per Cylinder; Proposed Rule,” Federal Register

69(124): 39275, June 29, 2004. (2004a)

U.S. Environmental Protection Agency (EPA). Draft 

NONROAD2004 Model. www.epa.gov/otaq/nonroadmdl.

htm. (2004b)

U.S. Environmental Protection Agency (EPA). EGrid 

Powerplant Emissions Database, 2004. www.epa.gov/

cleanenergy/egrid/index.htm. (2004c)

U.S. Environmental Protection Agency (EPA). Chicago 

Locomotive Idle Reduction Project (EPA420-R-04-003), 

March 2004. (2004d)

U.S. Environmental Protection Agency (EPA). Guidance 

for Quantifying and Using Long-Duration Switch 

Yard Locomotive Idling Emission Reductions in State 

Implementation Plans (EPA420-B-04-002), January 2004. 

(2004e)

U.S. Environmental Protection Agency (EPA). “Control of 

Emissions of Air Pollution from Nonroad Diesel Engines 

and Fuel; Final Rule,” Federal Register, 69(124): 38957, 

June 29, 2004. (2004f)

U.S. Environmental Protection Agency (EPA). Final 

Regulatory Analysis: Control of Emissions From Nonroad 

Diesel Engines (EPA420-R-04-007), May 2004. (2004g)

U.S. Environmental Protection Agency (EPA). Voluntary 

Diesel Retrofi t Program website, www.epa.gov/cleandiesel/

index.htm#voluntary, accessed September 16, 2005. 

(2005a)

U.S. Environmental Protection Agency (EPA). 2002 

National Emissions Inventory: Mobile Source Draft, June 

2005. www.epa.gov/ttn/chief/net/2002inventory.html. 

(2005b)

U.S. Environmental Protection Agency (EPA). 1999 

National Emissions Inventory Final Version 3.0, obtained 

from EPA staff, October 2005. www.epa.gov/ttn/chief/net/

1999inventory.html. (2005c)

U.S. Environmental Protection Agency (EPA). Voluntary 

Diesel Retrofi t Program: 2004 Grants, accessed 

September 19, 2005, from: www.epa.gov/dieselretrofi t/

dieselgrants2004.htm. (2005d)

West Coast Collaborative. West Coast Loan Fund to 

Reduce Locomotive Emissions Fact Sheet, August 2005. 

www.westcoastcollaborative.org/grants/revolving-loanfund.htm. (2005a)

West Coast Collaborative. Advanced Locomotive 

Emission Control System Fact Sheet, August 2005. www.

westcoastcollaborative.org/grants/ca-loco-hood.htm. 

(2005b)

West Coast Collaborative. Clean Air Partners 

Transportation System Liquefi ed Natural Gas Short 

Line Locomotive Project Fact Sheet, August 2005. www.

westcoastcollaborative.org/grants/ca-clean-air-transport.

htm. (2005c)

West Coast Collaborative. Cruise Liner Emission 

Reductions Incentives Project Fact Sheet, August 2005. 

www.westcoastcollaborative.org/grants/fi les/Cruise%20Li

ner%20Project%20Fact%20Sheet.pdf. (2005d)

West Coast Collaborative. Eastern Washington Farmer’s 

Diesel Emissions Reduction Program Fact Sheet, August 

2005. www.westcoastcollaborative.org/grants/fi les/WA_

Ag_DSNT_fact%20sheet.pdf. (2005e)
216 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

More than 97 percent of all vehicles on U.S. roads are 

personal cars and small trucks (U.S. Census Bureau, 2004; 

Davis, 2004). In 2002, more than 220 million of these 

vehicles were registered in the U.S. and they traveled over 

2.6 trillion miles, consuming nearly 130 billion gallons 

of fuel (Davis, 2004). Personal vehicle use continues to 

grow: annual vehicle mileage for cars and light trucks is 

projected to increase by more than 20 percent through 

2020 (EPA, 2000b).

Traditionally, most Americans have driven cars; in 1990, 

for example, light trucks (pick-ups, vans, sport utility 

vehicles (SUVs)) made up only about 25 percent of the U.S. 

vehicle fl eet (Davis, 2004). However, since 2000 nearly 50 

percent of all new vehicles sold in the U.S. have been light 

trucks—primarily SUVs and mini-vans—and light trucks 

now make up nearly 40 percent of the overall fl eet (Davis, 

2004). Until recently the trend toward larger vehicles was 

almost universally expected to continue; recent volatility 

in gasoline prices has begun to affect light truck sales, but 

it is impossible to say whether this will develop into a longterm trend.

The increasing use of heavier, less fuel-effi cient light 

trucks has increased both fuel use and exhaust emissions, 

eroding some of the effi ciency gains made through the mid1980s. As shown in Table 15.1, after a 69 percent increase 

in fuel effi ciency between 1975 and 1987 (the year average 

fuel effi ciency peaked), the average fuel effi ciency of the 

U.S. light-duty fl eet declined slightly through 1994 and has 

remained fl at since then, at about 21 miles per gallon (EPA, 

2005b). Stagnant fuel economy, coupled with a 60 percent 

increase in vehicle miles traveled, resulted in a 30 percent 

increase in fuel use between 1987 and 2002 (Davis, 2004).

This chapter discusses the current and projected inventory 

of direct fi ne particulate matter (PM2.5) and PM2.5-

precursor emissions from onroad light-duty vehicles, the 

regulatory authority to address these emissions from new 

and existing vehicles, and the control strategies that state 

and local areas can consider to reduce emissions as they 

develop their State Implementation Plans (SIPs).

Chapter 15

Light-Duty Cars and Trucks
 Chapter 15 - Light-Duty Cars and Trucks 217

Sector Profi le

The vast majority of light-duty vehicles in the U.S. fl eet 

have gasoline engines; in 1998 only 2.2 percent of lightduty vehicles on U.S. roads used diesel fuel (J.D. Power, 

2004). While some expect diesel vehicles to account for as 

much as 15 percent of the overall light-duty fl eet by 2014 

(J.D. Power, 2004), future regulations that will require 

emissions parity between light-duty gasoline and diesel 

engines will mitigate the potential negative air quality 

impacts of this trend.

Unlike current diesel engines, gasoline engines do not 

produce signifi cant direct PM2.5 emissions. A modern 

diesel engine without after-treatment will produce over 

eight times as much PM2.5 per gallon of fuel burned as a 

modern gasoline car engine. Therefore, despite the fact 

that there are over 40 times as many cars in the U.S. fl eet 

as heavy-duty diesel trucks, cars produce less than onethird as much direct PM2.5 as heavy-duty diesel trucks. 

Moreover, only about half of direct PM2.5 emissions from 

cars comes from engine exhaust; the rest comes from 

brake and tire wear (EPA, 2005f).

The light-duty gasoline vehicle fl eet is a much more 

important contributor to emissions of nitrogen dioxides 

(NOx), a PM2.5-precursor. In fact, light-duty gasoline 

vehicles produce about 46 percent of total NOx emissions 

from onroad vehicles and account for about 16 percent of 

all NOx emissions, including those from nonroad diesel 

and stationary sources (EPA, 2005f).

While sulfur dioxide (SO2) is also a PM2.5-precursor, all 

mobile sources together—including both light- and heavyduty onroad vehicles and all nonroad equipment—produce 

about 2 percent of total annual SO2 emissions nationwide. 

Moreover, this contribution will be reduced dramatically 

beginning in 2006 when allowable fuel sulfur levels for 

both gasoline and diesel fuel fall by over 80 percent (EPA, 

2004).

Efforts to address the contribution of the light-duty 

gasoline vehicle fl eet to ambient PM2.5 levels should focus 

on reducing precursor NOx emissions. To the extent that 

efforts are made to reduce direct PM2.5 emissions from 

light-duty vehicles, reducing emissions from brake and 

tire wear are every bit as important as reducing exhaust 

emissions (EPA, 2005f).

Regulatory Authority

As discussed in Chapter 4, the Clean Air Act gives EPA 

primary authority to regulate emissions from new onroad 

vehicles, including light-duty cars and trucks. California 

has authority to adopt its own emissions standards for new 

vehicles, as long as they are at least as stringent as federal 

standards. Other states can adopt either the California or 

the federal standards.

As discussed below, California standards for cars and light 

trucks have historically been more stringent than federal 

standards. This trend has continued with California’s 

recent effort—which is currently being litigated—to 

begin regulating greenhouse gas emissions from the lightduty fl eet. States and localities are free to set their own 

standards for existing onroad vehicles.

New Cars and Light Trucks

EPA began regulating emissions from new light-duty 

vehicles in the 1970s and continued tightening emissions 

standards over the years that followed. Most vehicles on 

the road today were manufactured subject to the Tier 1 

standards that were adopted in 1991 and phased in between 

the 1994 and 1997 model years. These standards allowed 

higher NOx emissions from light-duty trucks than from 

cars and also allowed higher NOx and PM emissions from 

diesel than from gasoline vehicles (EPA, 2000a). 

In 2000, EPA adopted Tier 2 standards for light-duty 

vehicles, which will be phased in between the 2004 and 

Table 15.1

U.S. Light-Duty Vehicle Fleet

Average 

Characteristics

1975 1987 2005

Fuel economy (mpg) 13.1 22.1 21.0

Weight (lb) 4,060 3,220 4,089

Horsepower 137 118 212

0-to-60 time (secs) 14.1 13.1 9.9

Truck sales (%) 19% 28% 50%

Source: EPA, 2005b

Fig 15.1 Light Duty Vehicle Registrations

Source: ORNL, 2004
218 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

2009 model years. The Tier 2 standards apply the same 

absolute emissions limit (grams per mile) to virtually all 

passenger vehicles regardless of size or weight, including 

cars, pick-up trucks, vans and SUVs. They also apply the 

same limit regardless of the fuel used, so that new lightduty diesel vehicles will have to be as clean as vehicles 

with gasoline engines (EPA, 1999, 2004).

The Tier 2 standards allow vehicle manufacturers to certify 

to any one of eight “bins” with different emissions levels; 

Bin 1 is the cleanest, with the most stringent standards, 

while Bin 8 has more lenient standards. The average 

NOx emissions from all vehicles that a manufacturer sells 

must be no more than 0.07 grams/mile, equivalent to Tier 

2, Bin 5. This is almost 90 percent lower than the Tier 

1 NOx standard for cars. The Tier 2 PM standard is also 

90 percent lower than the corresponding Tier 1 standard 

(EPA, 2000a; 2004).

Based on normal fl eet turnover, EPA estimates that annual 

NOx and PM emissions from light-duty vehicles will fall 

by 66 percent and 5 percent, respectively, through 2020 as 

new vehicles that comply with Tier 2 regulations enter the 

fl eet and older vehicles are retired (EPA, 1999). Emissions 

are expected to decline despite a projected 20 percent 

increase in annual vehicle miles traveled during that time 

period.

EPA does not regulate carbon dioxide (CO2) or other 

greenhouse gas emissions from vehicles. The position 

taken by the current administration is that the Clean Air 

Act does not authorize EPA to regulate greenhouse gas 

emissions from any source. This issue is currently being 

litigated.

The Department of Transportation (DOT) imposes 

Corporate Average Fuel Economy (CAFE) requirements 

on auto manufacturers. Current CAFE standards require 

manufacturers to maintain a car-fl eet-average fuel 

economy of 27.5 miles per gallon and an average fuel 

economy of 21.0 miles per gallon for light trucks (STAPPA 

and ALAPCO, 2005). Higher fuel economy standards 

decrease the amount of pollution emitted per mile, since a 

vehicle is using less fuel per mile.

DOT recently proposed revised CAFE standards that 

will begin to close the “SUV loophole” in the current 

regulations. The proposed standards divide light trucks 

into six categories based on vehicle footprint. The smallest 

truck category would be required to achieve an average 

fuel economy of 28.4 miles per gallon in 2011, while the 

largest would be required to achieve only 21.2 miles per 

gallon. The proposed revisions do not increase CAFE 

requirements for cars, nor do they extend fuel economy 

requirements to vehicles over 8,500 pounds (lb)—a 

category that includes such vehicles as the Hummer 

H2, Ford Excursion and Chevy Suburban (STAPPA and 

ALAPCO, 2005).

Fuel Quality

EPA has authority to regulate fuels and fuel additives 

used in light-duty vehicles, based on direct health effects 

from the fuel and the effect of the fuel on the ability of 

vehicles to meet emissions standards. In the past, this has 

resulted in rules banning lead in gasoline, as well as limits 

on the volatility of gasoline sold in the summer to reduce 

evaporative emissions.

In addition, the Clean Air Act, beginning in 1995, 

required that certain cities with severe ozone problems 

use reformulated gasoline (RFG) in the summer, and that 

areas in nonattainment for carbon monoxide (CO) use 

oxygenated gasoline in the winter. The Clean Air Act 

requires the use of RFG in cities in 14 states, but it allows 

limited opt-in for other areas. Currently, RFG is used 

in part or all of 19 states and the District of Columbia;1

approximately 30 percent of all gasoline sold in the U.S. is 

reformulated (EPA, 2005c).

RFG is formulated to meet a number of different 

specifi cations aimed at reducing emissions of ozone 

precursors and toxics such as benzene. One of these 

requirements is that it contains 2 percent oxygen by 

weight. The most commonly used oxygenate additive is 

ethanol, which is manufactured primarily from corn in 

midwestern states. Another additive that can be used as an 

oxygenate is methyl tertiary butyl ether (MTBE). MTBE 

is controversial because it can contaminate ground water. 

In addition, many people believe that RFG does not need 

to contain oxygen to improve air quality. California, New 

York and Connecticut petitioned EPA to have the oxygen 

requirement removed from their RFG standards, but EPA 

denied their requests (EPA, 2005c).

The Energy Policy Act of 2005 removed the requirement 

for RFG to contain oxygen, effective immediately in 

California and beginning in May 2006 everywhere else. 

While early versions of the legislation also contained an 

outright ban on MTBE in gasoline, this provision did not 

make it into the enacted law. California, New York and 

Connecticut have all taken individual action that partially 

or completely bans the use of MTBE in gasoline.

The Energy Policy Act of 2005 also contains a requirement 

that renewable fuels begin to make up a specifi ed portion of 

the gasoline sold in the U.S. The law requires that 4 billion 

gallons of renewable fuel be used in 2006, increasing to 7.5 

billion gallons per year in 2012. The most likely fuel to be 

used to meet this requirement is ethanol (more below).

1. California, Connecticut, Delaware, the District of Columbia, Georgia, 

Illinois, Indiana, Kentucky, Louisiana, Maryland, Massachusetts, Missouri, New Hampshire, New Jersey, New York, Pennsylvania, Rhode 

Island, Texas, Virginia and Wisconsin.
 Chapter 15 - Light-Duty Cars and Trucks 219

The Energy Policy Act of 2005 also allows opt-in to 

the RFG program at the request of a state, for the 11 

northeastern states in the Ozone Transport Region.

Based on the detrimental effect of sulfur on modern 

emissions after-treatment systems, EPA has also recently 

focused on reducing sulfur levels in both gasoline and 

diesel fuel. The Tier 2 light-duty regulations require that 

most gasoline refi ners and importers meet a corporate 

average sulfur standard of 120 parts per million (ppm), 

with an absolute cap of 300 ppm, beginning in 2004. This 

will be reduced to an average of 30 ppm with a cap of 80 

ppm by the end of 2006 (EPA, 2004).

As discussed in Chapter 4, The Clean Air Act, if EPA 

has regulated a fuel characteristic or component, states 

other than California may not adopt either their own or 

California’s regulation—they must follow the federal 

regulation. The only exception to this is the situation in 

which the Administrator fi nds that state regulation is 

necessary for achieving the National Ambient Air Quality 

Standards (NAAQS). On the other hand, California may 

adopt its own fuel regulations.

Other Regulations: California

Under the Clean Air Act, California can set its own 

emissions standards, even for new vehicles. California 

can also establish its own requirements for fuels and fuel 

additives.

The Tier 1/Low Emission Vehicle (LEV) California 

standards in effect through 2003 were very similar to Tier 

1 EPA standards, though they included additional, more 

stringent “low emission vehicle” regulatory categories 

(Transitional Low Emission Vehicle (TLEV), Low 

Emission Vehicle (LEV), Ultra-Low Emission Vehicle 

(ULEV) and Super Ultra-Low Emission Vehicle (SULEV)) 

for vehicles 6,000–14,000 lb gross vehicle weight). 

The Tier 1/LEV program established an increasingly 

stringent fl eet-average requirement for emissions of nonmethane organic gases (NMOG), which required auto 

manufacturers to certify an increasing share of their 

total vehicle sales in the lower emissions categories. The 

Tier 1/LEV program also required auto manufacturers to 

begin selling limited quantities of Zero Emission Vehicles 

(ZEVs), which at the time were generally battery-electric 

vehicles. In addition, unlike the EPA Tier 1 standards, 

the California Tier 1/LEV standards applied the same 

numerical emissions limits to both gasoline and diesel cars 

and light trucks (EPA, 2000a).

Beginning with the 2004 model year, California began 

to phase in LEVII standards. LEVII eliminates the Tier 

1 and TLEV regulatory categories, signifi cantly reduces 

allowable PM and NOx emissions in the LEV and ULEV 

categories and establishes a SULEV category for vehicles 

less than 6,000 lb gross vehicle weight. LEVII also 

establishes Partial Zero-Emission Vehicle (PZEV) and 

Advanced Technology Partial Zero-Emission Vehicle (ATPZEV) categories. To certify as a PZEV or AT-PZEV, a 

vehicle must meet SULEV emissions standards, have zero 

fuel evaporative emissions and carry a 15-year/150,000 

mile full emissions warranty. PZEV and AT-PZEV 

vehicles can be used by auto manufacturers to meet 

California’s ZEV requirements (CARB, 1999).

California’s LEVII standards apply to all cars and light 

trucks weighing less than 8,500 lb—meaning that most 

pick-ups and SUVs in California will be required to meet 

the same standards as cars. Under LEVII, the LEV and 

ULEV NOx and PM limits are the same as EPA Tier 2, Bin 

5; and the SULEV NOx and PM limits are the same as EPA 

Tier 2, Bin 2 (DieselNet, 2005).

The LEVII standards extend the requirements for 

automakers to certify increasing percentages of vehicles 

in the ULEV and SULEV categories. As a result, fl eetaverage emissions levels for new vehicles sold in California 

will continue to decline through 2010 (CARB, 1999).

In September 2004 the California Air Resources Board 

(CARB) adopted new rules to regulate greenhouse 

gas emissions from cars and light trucks, including 

CO2, methane, nitrous oxide, and hydrofl uorocarbons. 

(Unlike the other substances, hydrofl uorocarbons do not 

typically occur in engine exhaust but are used in vehicle 

air conditioning systems.) These new regulations are 

currently scheduled to phase in between the 2009 and 2016 

model years. CARB estimates that the new regulations 

will reduce greenhouse gas emissions from California’s 

light-duty vehicle fl eet by 18 percent in 2020 compared to 

today, and by 27 percent in 2030 (CARB, 2004b).

Automakers have fi led a legal challenge to the CARB 

greenhouse gas regulations, contending that they are, in 

effect, fuel economy standards and that only Congress has 

authority to set such standards.

State Authority

While the Clean Air Act precludes states other than 

California from implementing their own emissions 

regulations for new vehicles, states are allowed to adopt 

California regulations in lieu of EPA regulations. A 

number of states have exercised this important authority. 

To date, at least ten states have adopted or moved to adopt 

California’s low-emissions vehicle program; nine have 

adopted California’s heavy-duty diesel truck standards 

for model years 2007 and later; and 13 have adopted 

California’s diesel truck “not-to-exceed” requirements 

(STAPPA and ALAPCO, 2005b).

As of January 2006, eight states have adopted California’s 
220 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

light-duty vehicle greenhouse gas regulations (Washington 

Post, 2006). Many of these states have also supported a 

legal challenge to EPA’s determination that CO2 cannot be 

regulated under the Clean Air Act, which is being led by 

Massachusetts. (The D.C. Circuit Court of Appeals ruled 

against Massachusetts and the other states in the fi rst round 

of litigation, but it appears unlikely that the case will end 

there (Commonwealth of Massachusetts v. EPA, 2005).)

Despite the restrictions on state regulation of new vehicles, 

the Clean Air Act does not limit the authority of state and 

local areas to set standards for existing onroad vehicles. 

In fact, this responsibility falls primarily to the various 

states given that EPA’s role in regulating existing lightduty vehicles is limited to ensuring compliance with new 

vehicle standards throughout the defi ned useful life of the 

vehicle.

Emissions Control Opportunities

Virtually all cars and light trucks on the road today already 

rely on catalytic converters (“after-treatment” devices) in 

the tailpipe to comply with current EPA Tier 1 emissions 

standards. Improvements in the effi ciency of these devices, 

along with changes to engine design, were required to meet 

the EPA Tier 2 and California LEVII standards.

However, it is unlikely that the availability of these 

improved after-treatment technologies and engines will 

drive a retrofi t market for cars and light trucks. Given 

the relatively high turnover rate of the light-duty fl eet, 

as well as typical ownership patterns, retrofi tting or 

repowering existing light-duty vehicles is not a practical 

way to achieve signifi cant emissions reductions. This is 

different from the situation for the heavy-duty diesel fl eet, 

where future emissions regulations have already spurred 

the development of a retrofi t market and where retrofi tting 

existing vehicles is considered a key pollution control 

strategy (see Chapters 12, 13, and 14).

Most emissions reductions from the light-duty fl eet will 

have to come from fl eet turnover, as new vehicles that 

meet more stringent standards replace older vehicles, and 

from net reductions in total fuel usage by the sector. As 

discussed above, natural turnover is expected to produce 

signifi cant NOx reductions. However, given that both the 

EPA and California emissions standards include a range of 

certifi cation bins, not all new vehicles will have the same 

emissions levels. This means that there is an opportunity 

to accelerate emissions reductions from fl eet turnover by 

encouraging early retirement of the oldest, most polluting 

vehicles and their replacement by low emitting new cars 

and light trucks. The entry of new vehicles that use 

alternative, cleaner fuels can also play a role.

In addition, changes in personal behavior and in the 

transportation system that reduce vehicle miles traveled 

and/or relieve congestion will also reduce emissions from 

the light-duty fl eet. Strategies can include smart growth 

development to promote dense, mixed-use communities 

that allow cycling, walking and easier use of public transit 

for commuting and other trips, as well as improvements to 

and expansion of existing public transit infrastructure.

Reducing and enforcing highway speed limits can also 

reduce fuel usage and emissions from the light-duty fl eet, 

since cars operated above about 60 miles per hour are less 

fuel effi cient.

Cleaner Vehicles

As discussed above, EPA Tier 2 emissions regulations 

require that the “average” new car produce no more than 

0.07 grams per mile of NOx. However, the cleanest vehicles 

will be certifi ed to produce only 0.02 grams/mile—over 70 

percent less—while some light trucks will be allowed to 

produce 0.60 grams/mile—850 percent more—through 

model year 2006 (EPA, 2004). Clearly, not every new 

vehicle will have the same environmental performance.

EPA maintains a list of the most environmentally friendly 

vehicles based on certifi cation data (Green Vehicle Guide). 

For the 2006 model year, the Guide includes 28 different 

gasoline models that attain EPA’s highest rating of 9.5 

because their NOx emissions were certifi ed to the lowest 

level of 0.02 grams per mile in at least one available 

confi guration (EPA, 2005a). These models include small 

and mid-size sedans, several small wagons, hybrid-electric 

sport utility vehicles and performance cars. 

Not surprisingly, all of these models also achieved an EPA 

“greenhouse gas score” of at least 7.0—equivalent to a 

combined city-highway EPA fuel economy rating of 26–29 

miles per gallon (EPA, 2005a). Because exhaust emissions 

are created by the burning of fuel, in general the higher the 

average fuel economy a vehicle has, the lower the gram per 

mile emissions will be.

A review of California certifi cation data shows that, as of 

November 2005, there were at least 71 gasoline-powered 

2006 model cars and light trucks that achieve LEVII 

ULEV emissions standards, and an additional 13 models 

that achieve LEVII SULEV standards. These include 

small and mid-size sedans, wagons, small and mediumsize sport utility vehicles and performance cars. In 

addition, 24 models meet the PZEV emission requirements 

(CARB, 2005b).

Some of these models are hybrid electric vehicles, which 

achieve better fuel economy by combining a gasoline 

engine with a small battery pack and one or more electric 

motors to better manage energy usage throughout the 

driving cycle.
 Chapter 15 - Light-Duty Cars and Trucks 221

While ULEV and SULEV certifi ed gasoline vehicles 

typically cost the same or only marginally more than 

equivalent higher emitting vehicles, the most popular 

hybrid car, the Toyota Prius, costs approximately $3,000 

more than a comparable gasoline car. Other hybrid electric 

cars and light trucks can cost as much $6,000 more than 

the same vehicle with a gasoline engine (DOE, 2005). At 

least some of this price difference can be recovered from 

fuel savings over the life of the vehicle and tax breaks.

Cleaner Fuels

While there are a number of alternative formulations of 

diesel fuel that produce lower emissions than standard 

diesel (see Chapter 12), the practical alternatives to 

gasoline are more limited. The only commercially 

available liquid fuel that can be used as an alternative to 

gasoline for cars and light trucks is ethanol, an alcohol 

produced from corn and other agricultural commodities.

Some of the RFG currently sold in a number of cities 

during summer months, as well as some of the oxygenated 

gasoline sold in numerous cities in the winter, contains 

up to 10 percent ethanol added as an oxygenate. While 

the Energy Policy Act of 2005 removes the oxygenate 

requirement for RFG, future “standard” gasoline sold 

in various areas is likely to contain ethanol to meet the 

mandate for renewable fuel content that is also included in 

that law.

In some parts of the country, an “E85” blend of 85 percent 

ethanol and 15 percent gasoline is sold commercially. 

Standard gasoline engines and fuel systems must be 

modifi ed slightly to operate on fuel with a high percentage 

of ethanol and some auto manufacturers produce models 

with “fl ex fuel” engines that can operate on standard 

gasoline, ethanol, or any mixture of the two, including 

E85.

According to the U.S. Department of Energy (DOE), 

there are at least ten 2006 models of mid-size sedans, 

pick-up trucks, mini-vans and SUVs available from the 

manufacturer with fl ex fuel engines (DOE, 2005). These 

vehicles are certifi ed to either LEV or ULEV emissions 

standards and, according to EPA, can have up to 20 

percent lower PM emissions, up to 10 percent lower NOx

emissions and up to 15 percent lower VOC emissions when 

operated on E85 instead of standard gasoline (EPA, 2002). 

These vehicles are generally no more expensive than their 

gasoline equivalents.

Ethanol has 30 percent lower energy content per gallon 

than gasoline, so the fuel economy (miles per gallon) of a 

vehicle operated on E85 will be less than the fuel economy 

of the same vehicle operated on gasoline (DOE, 2005c). 

According to DOE, in September 2005 the average 

price of E85 was $2.41 per gallon, about 13 percent less 

than the average price of gasoline, at $2.77 per gallon 

(DOE, 2005b). Given this price differential, it would be 

marginally more expensive (dollars per mile) to operate a 

fl ex-fuel vehicle on E85 instead of gasoline.

Engines are also available for cars and light trucks that 

operate on natural gas. DOE lists several 2005 and 2006 

models available from the manufacturer with dedicated 

natural gas engines and/or bi-fuel engines that can operate 

on either natural gas or gasoline (DOE, 2005). These 

dedicated natural gas and bi-fuel engines are certifi ed to 

either ULEV or SULEV emissions standards and have 

no evaporative hydrocarbon emissions due to the use of a 

sealed fuel system. 

It is also relatively easy to convert a standard gasoline 

vehicle to operate on natural gas, although emissions can 

actually increase if the conversion is not done properly 

(ICCT, 2005). There are a number of reputable companies 

that do conversions of new vehicles, primarily for fl eet 

operators. To ensure that actual emissions reductions are 

achieved, all natural gas vehicle conversions should be 

done using an EPA- or CARB-certifi ed conversion kit.

The most signifi cant difference between a gasoline and 

a natural gas vehicle is the fuel system: while gasoline 

is a liquid, natural gas is a gas, which is stored on the 

vehicle under high-pressure. Therefore, use of a natural 

gas vehicle requires access to a high-pressure natural gas 

fueling station. 

Given the cost and limited availability of public natural 

gas fueling stations, conversion to natural gas is most 

appropriate for light-duty fl eet vehicles that operate within 

a limited geographic area, such as taxis and utility service 

vehicles. In some cities it may already be practical to 

use a natural gas vehicle for private commuting; a more 

extensive natural gas fueling infrastructure would allow 

individuals even greater use of natural gas vehicles. 

The incremental cost of natural gas cars and light trucks 

can be $4,500 or more compared to an equivalent gasoline 

vehicle (DOE, 2005). Natural gas and gasoline engines 

have similar effi ciency, and natural gas is generally less 

expensive than gasoline for the same amount of energy. 

According to DOE, in September 2005 the average price 

of a “gasoline equivalent gallon” of natural gas delivered 

for use in a vehicle was $2.12, about 23 percent less than 

the average price of a gallon of gasoline, at $2.77 (DOE, 

2005b). Given this price differential, at least some of 

the incremental purchase cost of a light-duty natural gas 

vehicle can be offset over the life of the vehicle based on 

fuel cost savings. 

In response to California Tier 1/LEV requirements 

that mandated the introduction of ZEVs, many auto 

manufacturers have produced battery-electric vehicles in 
222 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

limited quantities in the past. Many of these vehicles were 

technically successful and gained a loyal following among 

a small number of customers. However, the limitations of 

current battery technology—these vehicles typically had 

a range of 100 miles or less per charge—made electric 

vehicles impractical for many uses. Their additional cost 

compared to gasoline vehicles also limited their appeal to 

the general public. All of the major auto manufacturers 

have since abandoned their electric vehicle programs in 

favor of developing hydrogen fuel cell technology and 

producing vehicles that meet California’s LEVII PZEV 

and AT-PZEV emissions standards. New electric vehicles 

are still available from several small California companies 

that convert gasoline cars to electric drive, but their utility 

for private or even fl eet customers is limited.

Hydrogen fuel cells produce electricity directly from 

gaseous hydrogen and oxygen in a low temperature 

chemical reaction for which virtually the only by-products 

are water and heat. A fuel cell vehicle is therefore a 

zero emissions vehicle, producing no PM, NOx or other 

harmful pollutants. Every major auto manufacturer is 

actively working on fuel cell technology, and a number 

of demonstration vehicles are on the road today. This 

work is partially funded by the federal and several state 

governments.

The current generation of fuel cell vehicles is signifi cantly 

more expensive than gasoline vehicles and also has 

limitations in terms of durability and range. In addition 

to improvements in the vehicle technology itself, fuel 

cell vehicles will require the development of hydrogen 

production, distribution and retail fueling infrastructure 

before they can be used widely. Current expectations are 

that fuel cell vehicles will not replace a signifi cant portion 

of the light-duty fl eet until 2030 or later.

Using Less Fuel

Some cars and trucks use signifi cantly less fuel than 

others to go the same number of miles. For vehicles with 

the same level of engine and after-treatment technology, 

burning less fuel creates fewer exhaust emissions. In 

general, the smaller and lighter the vehicle, the more fuel 

effi cient it will be.

Engine technology can also affect fuel use: some gasoline 

engines are more effi cient than others, and hybrid 

electric vehicles are more effi cient still. Other vehicle 

characteristics can also play a role: vehicles with manual 

transmissions still get 5–10 percent better fuel economy 

than most automatics, despite recent improvements in 

automatic transmission design. Cars with all-wheel drive 

are also less effi cient than cars with two-wheel drive 

(DOE, 2005d).

Public policies related to land use and transportation 

infrastructure and management also play a role in limiting 

light-duty vehicle emissions. Shared transportation is more 

effi cient than the use of single-occupancy vehicles, and 

public transportation is very effi cient if well-utilized. Nonmotorized transportation modes (walking, bicycling) are 

non-polluting. Additionally, measures that reduce vehicle 

miles traveled not only reduce total exhaust emissions from 

the light-duty fl eet, but also reduce direct PM2.5 emissions 

from brake and tire wear. Brake and tire wear accounts 

for almost half of the direct PM2.5 contribution from lightduty vehicles, but it is unaffected by the engine and fuel 

technologies previously discussed.

Higher traffi c speeds (up to about 60 miles per hour) from 

reduced congestion reduce total emissions. Keeping 

maximum highway traffi c speeds below about 60 miles 

per hour also limits fuel use, as higher speeds are less 

effi cient. While every car is slightly different, fuel 

economy generally deteriorates rapidly above about 60 

miles per hour. DOE estimates that for every fi ve miles 

per hour over 60, fuel economy is reduced by 5–7 percent 

(DOE, 2005d). While average highway speeds have been 

increasing across the country since the 1990s, it may be 

that the current high and rising price of gasoline and the 

resulting increased focus on personal vehicle fuel economy 

will create a hospitable environment for rolling back 

highway speed limits.

State and Local Policy Measures

Programs that encourage or mandate the early retirement 

or replacement of older cars and trucks, sales of the lowest 

emitting replacement vehicles available and the use of 

cleaner fuels can have an important impact on air quality.

These types of programs will probably provide the 

most signifi cant opportunities for states to control and 

reduce PM and NOx emissions from the light-duty fl eet. 

Whether these policies are voluntary or mandatory, their 

common focus is on accelerating the emissions reductions 

available from fl eet turnover. In addition, inspection and 

maintenance (I&M) programs for light-duty vehicles will 

continue to be an important tool for the attainment and 

maintenance of improved ambient air quality.

Approaches that improve the overall transportation system 

and thereby reduce single-occupancy vehicle trips as 

well as total light-duty vehicle miles traveled will also 

produce PM and NOx benefi ts based on reduced fuel use 

by the light-duty vehicle sector as a whole. These include 

programs that promote the use of public transportation, 

shared transportation and non-motorized modes; 

that reduce highway speeds; and that enhance traffi c 

management and reduce congestion.
 Chapter 15 - Light-Duty Cars and Trucks 223

Accelerating Fleet Turnover

While lower emitting vehicles are sometimes no more 

expensive than similar vehicles with higher emissions, that 

is not always the case. In addition, there are many factors 

besides cost that most people weigh when deciding which 

vehicle to buy, including size, engine power, safety and 

amenities. Environmental considerations do not always 

win out over these other factors.

One way to tip the balance is to provide monetary 

incentives for individual consumers and fl eet customers 

to make the “clean” choice when buying a new vehicle. 

Incentives can be in the form of a rebate, a tax credit or 

reduction, or a reduction in vehicle-related charges such as 

registration fees. Eight states2

 and the federal government 

currently provide some kind of purchase incentive for 

environmentally friendly vehicles (DOE, 2005).

In most cases, these purchase incentives consist of a 

state income tax rebate or a state sales tax exemption for 

some percentage of the incremental cost of purchasing a 

new environmentally friendly vehicle or, in some cases, 

of converting to a cleaner fuel or technology. The rebate 

percentages range from 30–100 percent of the incremental 

cost. Connecticut exempts eligible vehicles from all state 

sales taxes, while New Mexico exempts vehicles from the 

state excise tax (DOE, 2005).

Depending on the state, eligible vehicles include hybrid 

electric vehicles, electric vehicles and vehicles operated on 

natural gas, liquid petroleum gas, or E85. Colorado bases 

eligibility on EPA emissions standards, with those vehicles 

certifi ed to LEV standards eligible for a 50 percent rebate, 

those certifi ed to ULEV standards eligible for a 75 percent 

rebate and those certifi ed to SULEV standards eligible for 

an 85 percent rebate. Colorado also doubles the rebate, up 

to 100 percent of the incremental cost, for new vehicles 

that permanently replace vehicles that are ten years old 

or older (meaning that the old vehicles are scrapped, not 

resold). New Mexico provides its incentive only for hybrid 

electric vehicles that get at least 27.5 miles per gallon 

(DOE, 2005).

Most of these programs also provide incentives for the 

purchase/installation of alternative fueling infrastructure, 

such as natural gas fueling stations. Most programs are 

available to individuals and businesses, but some are 

available only to government-controlled fl eets within the 

state. Several states operate separate incentive programs 

for private entities and government fl eets.

Between 1992 and 2005 the federal government also 

provided a tax deduction of $2,000 for the purchase of a 

2. These states are California, Colorado, Connecticut, Illinois, Maine, 

New Jersey, New Mexico and New York. In addition, Vermont provides 

state income tax credits for manufacturers of electric, hybrid electric 

and alternative fuel vehicles with operations in the state. 

hybrid electric vehicle. The Energy Policy Act of 2005 

provides tax credits for the purchase of fuel cell, hybrid 

and alternative fuel vehicles, beginning in 2006 and 

running through 2010. For hybrids, the credit ranges from 

$250 to over $3,000 per vehicle, depending on how much 

of the vehicle’s power is provided by the electric motor/

battery pack instead of the gasoline engine, as well as its 

rated fuel economy. For alternative fuel vehicles, the credit 

is based on a percentage of the incremental cost compared 

to a standard gasoline vehicle.

Some states and cities are also offering individuals 

nonmonetary incentives to purchase cleaner vehicles. 

These range from permission to drive eligible vehicles with 

a single occupant in high-occupancy vehicle (HOV) lanes 

(Arizona, California, Georgia and Virginia), to exemption 

from state emissions tests (Maryland), to free parking at 

street meters and city-owned parking facilities (cities of 

Los Angeles, San Jose and Santa Monica in California).

Another way to accelerate fl eet turnover is to provide 

incentives for individuals to retire the oldest, most 

polluting vehicles earlier than they otherwise would. For 

example, the Bay Area Air Quality Management District 

(AQMD) in northern California will buy back pre-1985 

vehicles for $650 each. Eligible vehicles must be registered 

and operational—they are taken to a vehicle dismantler 

registered with the air district, where they are destroyed so 

that they cannot be resold and put back on the road (Bay 

Area AQMD, 2005).

California’s Bureau of Automotive Repair operates a 

similar program. It will pay motorists $1,000 for any 

vehicle that fails a Smog Check emissions inspection. 

Eligible vehicles must be taken to a registered dismantler 

to be scrapped (California Department of Consumer 

Affairs, 2005).

As a complement to these voluntary vehicle retirement 

programs, CARB is evaluating the feasibility of a 

voluntary vehicle repair program. Using remote sensing, 

such a program would identify eligible high emitting 

vehicles between biennial smog checks. Vehicle owners 

would be offered a fi nancial incentive to complete 

necessary repairs (Panson, 2005).

All of the above are voluntary programs. Though no 

examples of mandatory programs could be identifi ed for 

purposes of this report, approaches that might accomplish 

the same goals could include denying registration or 

imposing higher registration fees or more frequent 

emissions inspections on older vehicles. This would 

provide a greater monetary incentive for scrapping and 

replacing such vehicles. CARB is considering a mandatory 

requirement to replace or upgrade emissions control 

equipment (catalyst muffl ers, oxygen sensors, evaporative 

fi lter canisters) on older vehicles. Because the effi ciency 
224 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

of these components may degrade with age, mandatory 

scheduled replacements may provide signifi cant emissions 

benefi ts. CARB is currently operating a pilot program to 

determine the actual benefi ts of such an approach (Panson, 

2005) 

As discussed in previous sections, California has adopted 

more stringent new vehicle emissions standards than the 

Tier 2 EPA standards currently in effect. Under the Clean 

Air Act, other states may adopt the California standards 

and several have already done so. Doing so will accelerate 

emissions reductions from fl eet turnover, as virtually all 

new vehicles that enter the fl eet will be cleaner than they 

would be under EPA standards. States could complement 

this approach by requiring operators of publicly owned 

fl eets to purchase only ULEV and SULEV certifi ed 

vehicles.

Inspection & Maintenance

Studies have shown that a relatively small fraction of 

vehicles can create a disproportionate share of vehicle 

emissions (Niemeir, 2004). These vehicles may be 

poorly maintained or misadjusted or have malfunctioning 

emissions control equipment. Under the Clean Air Act, 

certain ozone and CO nonattainment areas are required 

to put I&M programs in place for light-duty vehicles. 

However, these requirements give the states a good deal 

of fl exibility as to the type of I&M program they adopt. 

Moreover, even states without a federal I&M mandate may 

implement a state I&M program where it is benefi cial as 

part of their SIP strategy.

I&M programs are designed to identify high emitters and 

require vehicle owners to repair them. Inspections can 

be performed on a regular basis, usually in conjunction 

with the renewal of vehicle registration and/or a statemandated safety inspection. Inspections can also be 

performed randomly using roadside pull overs. Mandatory 

repair requirements can be enforced by denying vehicle 

registration and/or by imposing a fi ne that is waived upon 

proof of repair.

Thirty-three states plus the District of Columbia currently 

have a light-duty I&M program in at least one city or 

county (EPA, 2003). The earliest programs are those in 

California and Idaho, which were implemented in 1984; 

the most recent are those in Louisiana and Missouri, which 

were implemented in 2000.

Some of these programs require only a visual inspection 

of the vehicle’s emissions control system components, 

but most require a tailpipe emissions test on most older 

vehicles to identify high emitters. There are a number of 

different methods of tailpipe testing, including idle-only 

tests and tests that require the use of a dynamometer to 

load up the engine for testing. There are also a number of 

different test cycles that can be used with a dynamometer; 

currently the most popular are the ASM2, ASM2525 and 

IM240 test cycles (EPA, 2003).

Starting with the 1996 model year, EPA began requiring 

that all new vehicles be equipped with an on-board 

diagnostic system (OBD). These systems use various 

sensors to identify failures of engine components or 

systems that are known to increase exhaust emissions. 

When a component fails, the OBD system lights an 

indicator on the vehicle dash to show that the engine 

requires service. Using software provided by the engine 

manufacturer, a trained mechanic can retrieve detailed 

information about the failure that can help to diagnose and 

repair the problem.

These OBD systems can also be used in an I&M program 

to identify vehicles with emissions-related problems that 

are potential high emitters, without the need for a tailpipe 

test. Currently, 16 states use an OBD scan to identify high 

emitters in their I&M programs for cars in the 1996 model 

year and newer; these vehicles do not undergo a tailpipe 

emissions test.

For many years, light duty I&M programs have been 

considered a key tool for reducing emissions of smogforming pollutants (NOx and VOCs), as well as CO 

emissions, from cars and light trucks. In its most recent 

program evaluation, California concluded that in 2002 

its I&M program resulted in NOx reductions of 158 tons 

per day, along with 360 tons per day of CO and 211 tons 

per day of hydrocarbons (CARB, 2004a). The reduction 

in NOx emissions was estimated to be approximately 18 

percent of total NOx emissions from the gasoline fl eet in 

California.

In 2002, a committee of the National Research Council 

of the National Academies of Sciences undertook an 

evaluation, funded by the federal government under 

the Congestion Mitigation and Air Quality grant 

program, of the effectiveness of pollution reduction 

projects. It concluded that “well structured inspection 

and maintenance programs” were the most cost-effective 

transportation-related strategies among those evaluated for 

reducing vehicle emissions (National Research Council, 

2002).

Transportation System Improvements

Transportation system improvements that have the 

potential to reduce total vehicle emissions generally fall 

into two broad categories: (1) changes that result in fewer 

trips and fewer miles traveled, especially by single- and 

low-occupancy private vehicles; and (2) changes that 

reduce roadway congestion, thus speeding up traffi c in 

and around urban areas and reducing idling emissions. 

In both categories, strategies can include physical 
 Chapter 15 - Light-Duty Cars and Trucks 225

infrastructure changes as well as operational changes and 

public education campaigns. Reduction in highway speed 

limits to 55–60 miles per hour and/or better enforcement 

of existing 55–65 mile per hour limits can also reduce 

emissions and fuel consumption from the light-duty fl eet.

Trip reduction efforts can focus on improving or 

supplementing existing public transportation options 

(bus, subway, light rail) in order to provide travelers with 

better alternatives to using their own vehicles. In addition 

to adding buses or subway lines, other approaches to 

improving public transportation include public education/

trip planning services, construction of park and ride 

facilities and provision of a guaranteed ride home (for 

example, by taxi) for regular riders who have to work late 

or who, for some other reason, miss the last scheduled bus 

or train.

Ride-sharing by private individuals also reduces vehicles 

miles traveled. In addition to the installing of HOV-only 

lanes on major commuting routes, strategies available 

to states and localities include providing equipment and 

services for van pools, as well as operating a ride-share 

information clearinghouse to connect individuals who are 

looking for commuting partners.

Strategies that encourage the use of non-motorized 

transportation modes (walking, bicycling) also reduce 

vehicle trips. Measures include the installation of 

sidewalks and bicycling/walking paths, as well as zoning 

and land use policies that promote denser development and 

integration of housing and commercial activities.

EPA recently recognized fi ve communities from California 

to Florida for their innovative approaches to such “Smart 

Growth” policies. New housing development in these 

communities includes features that facilitate walking 

and bicycling, proximity to existing transit hubs, a range 

of housing types, and integration with work, shopping, 

and leisure opportunities to foster a greater sense of 

community and reduce the use of private cars (EPA, 

2005d).

Finally, trip reduction efforts can focus on reducing the 

total number of commuting and other business trips 

altogether—for example, by encouraging telecommuting 

and greater use of teleconferencing for business meetings.

Many current trip reduction programs incentivize 

employers to provide better options for their employees’ 

commutes. EPA and DOT have developed a voluntary 

program called Best Workplace for CommutersSM. In 

addition to providing information for employers and 

employees, this program recognizes companies that 

meet a “national standard of excellence” by providing a 

minimum level of commuting benefi ts for their employees. 

The program’s benefi ts include a minimum $30 per 

month in transit or vanpool passes, a minimum payment 

of $30 per month in lieu of a subsidized parking space 

and telecommuting options that reduce total monthly 

commuting trips by 6 percent or more (DOT, 2005).

Federal tax law allows employers to provide up to $105 per 

month per employee in transit or vanpool benefi ts without 

paying any payroll taxes on that amount. Alternatively, 

employers can allow employees to reserve up to $105 per 

month for commuting expenses on a pre-tax basis. Either 

way, both employees and employers save money on taxes, 

reducing the cost of commuting (DOT, 2005). 

The State of Maryland provides an additional state tax 

credit of up to 50 percent of the cost of employer-provided 

commuting benefi ts up to a maximum value of $50 per 

month per employee. These tax credits can be claimed for 

the cost of employer-provided transit passes or vouchers, 

vanpool expenses, parking cash-out benefi ts or the costs of 

a guaranteed ride home program (Maryland DOT, 2005).

While these commuting programs are voluntary, California 

has implemented a mandatory “Parking Cash-Out Law.” 

The law requires certain employers who provide free 

parking for their employees to allow employees to “cash 

out” their parking space—that is, give up their parking 

space in return for a cash payment—as a means of 

providing additional monetary incentives for employees 

to walk, bicycle, carpool or take public transportation to 

work (CARB, 2005a). 

While increased use of public, shared and non-motorized 

modes of transportation can reduce congestion on crowded 

roadways, there are other, more direct ways to speed 

traffi c. Probably the simplest way is to improve identifi ed 

intersections to remove bottlenecks. In many places, 

computerization and better coordination of traffi c signals 

can also dramatically improve traffi c fl ow in specifi c 

corridors. Finally, more sophisticated traffi c management 

tools have become available over the last ten years. 

These tools are usually described under the general term 

“Intelligent Transportation Systems” or ITS.

All of these strategies can help to reduce emissions of 

PM2.5 and NOx from cars and light trucks by reducing 

vehicle travel and overall fuel use. 

References

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228 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

In many ways a microcosm of the cities they serve, 

airports comprise a wide variety of particulate matter (PM) 

and PM-precursor emissions sources, including power 

plants, construction equipment, shuttle buses, passenger 

vehicles and aircraft. In aggregate, the emissions from a 

large airport are comparable to those of a power plant or 

petroleum refi nery, although the characteristics of the 

source are obviously much different.

The dominant source of airport emissions, aircraft are 

a growing source of nitrogen oxides (NOx) emissions in 

the U.S. as a result of steady growth in air travel demand. 

Projections by the Federal Aviation Administration (FAA) 

suggest that fl ights of commercial air carriers will increase 

by 18 percent from 2002 to 2010 and 45 percent from 2002 

to 2020 in the U.S. (EPA, 2003). A signifi cant increase 

in air pollution emissions has accompanied this steady 

growth in air travel. Between 1970 and 1990, aircraft NOx

emissions are estimated to have increased by 133 percent 

(CCAP/NESCAUM, 2003); moreover, despite the adoption 

of new aircraft engine emissions standards, the general 

trend of increasing emissions is expected to continue 

(Schmidt, 2005).

State and local agencies have limited authority to 

regulate aircraft-related air pollution because the Clean 

Air Act preempts states from regulating aircraft engine 

emissions. However, aircraft are not the only source of 

emissions at airports. Though they account for a smaller 

share of airport-related emissions, ground transportation 

and service equipment and airport power facilities have 

provided opportunities for meaningful pollution reductions 

and continue to be a focus of emissions control efforts.1

For example, some airport operators have converted 

airport ground vehicles from diesel or gasoline to cleaner 

alternative fuels. In some cases—such as at the Los 

Angeles and Dallas/Fort Worth airports—federal or state 

agencies have imposed measures to bring severely polluted 

areas into attainment with the Clean Air Act’s air quality 

standards or to mitigate expected emissions increases from 

airport expansion projects.

This chapter discusses sources of emissions at airports, 

1. As some of these basic sources of emissions (e.g., boilers and buses) 

are discussed in other chapters of this report, the reader is referred to 

these sections for additional information.

Chapter 16

Airports
 Chapter 16 - Airports 229

the regulatory authority to address these sources, and the 

control strategies that state and local authorities might 

consider to reduce PM and PM-precursor emissions as 

they develop State Implementation Plans (SIPs).

Sector Profi le

As indicated above, airports comprise a wide variety 

of emissions sources, including mobile and stationary 

sources.

Fossil fuel combustion is the dominant source of airport 

PM2.5, sulfur dioxide (SO2) and NOx emissions. Various 

studies have estimated the emissions contributions of these 

facilities, focusing on individual components of the airport 

source category or, more broadly, on the entire scope of 

airport-related activities.

In a 2003 study, the Center for Clean Air Policy and the 

Northeast States for Coordinated Air Use Management 

(CCAP/NESCAUM) developed emissions inventories 

for three airports located in the Northeast: (1) Logan 

International Airport in Boston, Massachusetts, which 

serves roughly 27 million passengers per year; (2) Bradley 

International Airport in Windsor Locks, Connecticut, 

which serves roughly 6.3 million passengers per year; and 

(3) Manchester Airport in Manchester, New Hampshire, 

which serves roughly 2.8 million passengers per year. 

The study focused on three sources of airport-related 

emissions: aircraft main engines, auxiliary power units 

and ground service equipment.2

 The study excluded 

from the inventory ground access vehicles and stationary 

sources.3

Table 16.1 summarizes the NOx emissions estimates 

developed in the CCAP/NESCAUM study.4 In all 

2. Auxiliary power units are small jet engines onboard aircraft that 

provide electricity to a jet aircraft parked at a terminal gate.

3. Also, the CCAP/NESCAUM study estimates only aircraft emissions 

that occur below the “mixing height”—that is, only those emissions that 

are assumed to contribute to ground-level air quality problems.

4. SO2 and PM2.5 emissions were not estimated in the study.

cases, aircraft main engines were found to be by far the 

dominant source of emissions among the source categories 

evaluated. 

EPA reports a similar distribution of NOx emissions 

between aircraft and ground service vehicles in its 2002 

National Emissions Trends inventory (see Table 16.2). 

Nationwide, aircraft are estimated to have generated 85,616 

tons of NOx emissions in 2002, or less than 1 percent of 

all transportation-related NOx emissions (EPA, 2005a). 

By comparison, airport service vehicles are estimated to 

have generated 9,000 tons of NOx emissions in 2002 (EPA, 

2005b).

Nationwide, aircraft are estimated to have generated 7,535 

tons of SO2 emissions in 2002 (EPA, 2005a).

There is wide variation in EPA’s estimates of direct PM2.5

emissions from aircraft. EPA’s 2002 draft emissions 

inventory estimates annual emissions of 14,000 tons (EPA, 

2005a). Research projects are currently underway to better 

characterize aircraft particle emissions and improved data 

are expected in the coming years (Chou Wey, 2005).

Diesel-powered airport service vehicles are reported 

to have generated less than 1,000 tons of direct PM2.5

emissions in 2002 (EPA, 2005b).

The national pollution inventory does not tell the full 

Examples of Airport Emissions Sources

Mobile Sources Stationary Sources

aircraft main engines

aircraft auxiliary power units

ground service equipment 

(e.g., baggage tugs, belt 

loaders, pushback tractors)

ground access vehicles (e.g., 

passenger buses, vans, cars)

construction equipment

utility plants (e.g., power 

boilers and combustion 

turbines)

maintenance facilities

restaurants/catering facilities

emergency services

Table 16.1

Airport Emissions Inventories

Source

Annual NOx

Emissions 

(Tons, 1999)

% NOx

Emissions 

(1999)

Logan International Airport

Aircraft 2,644 86%

APUs 145 5%

GSEs 293 9%

Bradley International Airport

Aircraft 677 84%

APUs 30 4%

GSEs 96 12%

Manchester Airport

Aircraft 188 82%

APUs 8 3%

GSEs 33 14%

APU = auxiliary power units

GSE = ground service equipment

Source: CCAP/NESCAUM, 2003
230 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

story. Several urban areas that are in nonattainment for 

PM2.5 have one or more major airports within their airshed. 

Within these areas, airport-related activities are likely to 

contribute a higher share of regional emissions.

In a study of ten urban areas, EPA reports a projected 

increase in the contribution of aircraft to regional mobile 

source NOx inventories; specifi cally, the average aircraft 

contribution in these areas is expected to increase from 2 

percent in 1990 to about 5 percent in 2010 (EPA, 1999). 

In at least two of the cities studied, commercial aircraft 

are projected to contribute as much as 10 percent of total 

regional mobile source NOx emissions by 2010. This 

estimate refl ects the expectation that aircraft emissions 

are likely to increase, while emissions from other mobile 

source categories are projected to decline.

Some studies have developed airport inventories focused 

on a broader spectrum of sources, such as the LAX Master 

Plan EIS/EIR, which inventories emissions at the Los 

Angeles International Airport (LAX). The LAX inventory 

includes aircraft, auxiliary power units, motor vehicles 

(on-airport) and stationary sources. In 1996, the airport 

generated total NOx emissions of 5,175 tons and total SO2

emissions of 183 tons. According to the inventory, aircraft 

accounted for 74 percent of NOx emissions, ground service 

equipment accounted for 7 percent, auxiliary power 

units accounted for 1 percent, traffi c on airport roadways 

accounted for 8 percent and stationary sources accounted 

for 9 percent. In terms of SO2 emissions, aircraft 

accounted for 91 percent of the inventory, ground service 

equipment accounted for 4 percent, traffi c on airport 

roadways accounted for 1 percent and stationary sources 

accounted 4 percent (Camp Dresser & McKee, 2001).

In sum, while airports may represent a small share of 

mobile source emissions overall, the anticipated increase 

in their emissions and their close proximity to large urban 

centers make them a candidate for pollution control efforts 

(see Table 16.3).

Emission Control Opportunities

The technical control options for reducing airport 

emissions are discussed below. Programs and policies are 

discussed in the sections that follow.

Aircraft and Auxiliary Power Units

Improving aircraft engine technologies and overall aircraft 

design can reduce fuel consumption and emissions. There 

are several promising technologies for reducing aircraft 

emissions, as described by CCAP/NESCAUM (2003). 

The National Aeronautics and Space Administration 

(NASA) conducts most of the original research and 

Table 16.3

Airport PM2.5 Attainment Status

Airport

National 

Ranka PM2.5 Status

Hartsfi eld Atlanta Intl 1 Nonattainment

Chicago O’Hare 2 Nonattainment

Los Angeles Intl 3 Nonattainment

Dallas/Fort Worth Intl 4 Attainment

Phoenix Sky Harbor Intl 5 Attainment

Denver Intl 6 Attainment

Las Vegas McCarran Intl 7 Attainment

George Bush Intl 8 Attainment

Minneapolis - St Paul Intl 9 Attainment

Detroit Metropolitan 10 Nonattainment

John F Kennedy Intl 11 Nonattainment

Newark Liberty Intl 12 Nonattainment

a. National rank in terms of enplanements (the number of 

passengers leaving from an airport).

Source: FAA, 2003

Table 16.2

National Airport Emissions (2002)

Source Category PM2.5 SO2 NOx

Tons/Year Percent 

of Sector 

Emissions

Tons/Year Percent 

of Sector 

Emissions

Tons/Year Percent 

of Sector 

Emissions

Aircraft 13,964 94% 7,535 84% 85,616 81%

Ground service vehicles 871 6% 1,457 16% 19,960 19%

Total 14,835 100% 8,992 100% 105,573 100%

NR = not reported 

a. Rounded to thousands.

Source: Billings, 2004; EPA, 2005a
 Chapter 16 - Airports 231

development work on new turbine engine technology and 

has a multi-year program to develop lower-emitting jet 

engines. One target is to introduce an engine that can 

emit 70 percent less NOx than the limits set by current 

international standards.5

 Aircraft engine manufacturers 

have also been working to develop engines with lower 

NOx emissions while improving fuel effi ciency. However, 

these approaches are not the focus of this report because 

the Clean Air Act preempts states from setting their own 

aircraft emissions standards.

Changing aircraft operations represents a second category 

of options for reducing emissions. The options include 

minimizing the use of reverse thrust on landing, using 

lower engine power at takeoff, using a single engine when 

taxiing and shutting off main engines while idling. These 

options are also not emphasized in this report because, in 

some cases, safety concerns may limit their application. 

Also, single engine taxi is already widely practiced by U.S. 

airlines. Delta, for example, reports that single engine 

taxi has saved the company about 6.3 million gallons of 

fuel during the fi rst eight months of 2005 (Delta Airlines, 

2005). 

A third option for reducing aircraft-related emissions is 

to retrofi t airport gates with power and preconditioned air 

to reduce the use and emissions associated with aircraft 

auxiliary power units and ground power units. Gatebased power and air conditioning hook-ups have become 

increasingly common at airports. These hook-ups 

eliminate or reduce the use of higher-emitting on-board 

auxiliary power units powered by jet fuel and dieselpowered mobile ground power units. Gate electrifi cation 

requires an up-front capital investment but, once installed, 

the system produces fuel and labor savings that typically 

result in a relatively short payback time of less than two 

years (CCAP/NESCAUM, 2003). Because of the economic 

benefi ts of gate electrifi cation, many larger airports have 

already adopted the technology. Increased use of these 

systems could further reduce emissions.

Ground Service Equipment

Ground service vehicles—including baggage tugs, 

belt loaders and aircraft pushback tractors—are used 

in a variety of applications, including aircraft fueling, 

transporting cargo to and from aircraft, loading cargo, 

transporting passengers to and from aircraft, baggage 

handling, lavatory service and food service.

As for other mobile sources, there are three basic 

approaches for reducing emissions from diesel- or 

gasoline-powered ground service equipment: use a cleaner 

engine, add a retrofi t device or use a cleaner fuel.

5. The 70 percent NASA target is in relation to the standards adopted at 

the second meeting of the International Civil Aviation Organization’s 

(ICAO) Committee on Aviation Environmental Protection (CAEP), 

which became effective in 1996.

Cleaner Engines. New nonroad diesel engines certifi ed 

to the latest EPA standards emit 30–60 percent less NOx

and PM than the unregulated engines built a few years ago. 

(See Chapter 14, Nonroad Equipment, for a discussion 

of diesel engine standards.) These reductions have come 

from changes in diesel engine design, most notably better 

control of lubrication oil, higher fuel injection pressures 

and the addition of electronic fuel control. In some cases, 

particularly Tier 3 engines with electronic fuel control, 

lower emissions have been accompanied by improved 

fuel effi ciency. Removing older engines from service 

and replacing them with new engines can therefore have a 

large emissions benefi t.

Retrofi t Devices. The second basic option for reducing 

emissions from ground service equipment is to retrofi t 

existing diesel equipment with oxidation catalysts and 

particulate fi lters to reduce PM emissions. The more 

stringent standards that EPA has adopted for nonroad 

diesel equipment will not take effect for many years and 

will not apply to the fl eet of existing vehicles. Diesel 

retrofi t technologies may be an option for ground service 

equipment depending on the duty cycle of the vehicle and 

the availability of controls. Diesel retrofi t technologies are 

discussed in Chapter 12, Diesel Engine Technologies.

Cleaner Fuels. Another option for reducing emissions 

from diesel-powered ground service equipment is to rely 

on ultra-low-sulfur diesel fuel—that is, fuel with sulfur 

levels below 15 parts per million (ppm) by volume—prior 

to the applicable regulatory compliance deadline for 

nonroad diesel engines in 2010. As discussed in the section 

of this chapter on regulatory authority, EPA’s nonroad 

clean diesel regulations require the use of ultra-low-sulfur 

diesel fuel beginning in 2010. Switching a conventional 

vehicle to lower sulfur fuel will reduce PM and SO2

emissions to some extent; however, the primary advantage 

of switching to a lower sulfur fuel is that after-treatment 

devices, such as diesel particulate fi lters, can be used with 

the fuel. Lower sulfur fuel improves the performance and 

durability of advanced control technologies. In California, 

state regulations will require ultra-low-sulfur diesel fuel 

for onroad and nonroad applications starting in 2006, 

several years before the federal requirements. Chapter 12, 

Diesel Engine Technologies, provides more information on 

the use of low-sulfur diesel fuel and after treatment control 

options.

Another option for reducing emissions is to replace dieseland gasoline-powered ground service equipment with 

equipment powered by alternative fuels such as electricity, 

compressed natural gas (CNG) and liquid propane 

gas (LPG). The CCAP/NESCAUM study discussed 

previously reports a cost of about $1,700 for converting 

belt loaders and baggage tractors to LPG; the cost of LPG 

conversion for aircraft push back tractors is estimated 

at approximately $2,700 (CCAP/NESCAUM, 2003). 
232 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

According to the same study, converting gasoline-powered 

ground service equipment to CNG costs approximately 

$5,000 (CCAP/NESCAUM, 2003). 

The primary barrier to converting airport service 

equipment to alternative power sources, like CNG and 

electricity, is the initial capital investment required to 

install the necessary infrastructure. CNG and LPG both 

require refueling and storage infrastructure in addition 

to the purchase of new alternative-fueled vehicles or the 

conversion of existing gasoline and diesel vehicles. CCAP/

NESCAUM (2003) report a cost of $750,000 for a 50-

vehicle, fast-fi ll CNG refueling station. Electric vehicles 

require battery-charging systems. Government grants 

can help mitigate these costs. Once made, the investment 

yields signifi cant pollution reductions in addition to other 

benefi ts such as lower fuel costs, lower maintenance costs 

and longer engine life.

Electric-powered ground service equipment has been 

a popular option for reducing emissions, particularly 

in warmer regions, where cold weather does not affect 

battery performance. For example, the Burbank Airport 

in California has invested $1.3 million in a system of 42 

battery chargers for electric ground service equipment at 

all 14 of its gates (BGP Airport Authority, 2005). By the 

end of 2005, the airport authority aims to have 70 percent 

of its ground service fl eet powered by electricity, based on 

a commitment by Southwest Airlines to convert most of its 

fl eet by the end of 2005. According to CCAP/NESCAUM 

(2003), electric ground service equipment is initially more 

expensive than diesel equipment—for example, an electric 

baggage tractor costs 27 percent more than a diesel 

version. However, these additional costs are largely offset 

Table 16.5

Cost-Effectiveness of Converting Gasoline and 

Diesel Ground Service Equipment to Electricity

Equipment Fuel Type

CostEffectiveness 

($/Ton of NOx)

Baggage tractor Gasoline 1,900

Diesel 5,800

Belt loader Gasoline Cost savings

Diesel Cost savings

Aircraft tug Gasoline Cost savings

Diesel 2,800

Source: CCAP/NESCAUM, 2003

by reduced fuel and maintenance costs over the life of the 

machine.

Based on fi gures reported by Southern California Edison, 

it costs $3.97 per day to charge an electric-powered belt 

loader, compared to $8.18 to fuel a gasoline-powered belt 

loader (Reinhardt, 2005). Sources also report reduced 

maintenance costs for electric vehicles, which eliminate 

the need for tune-ups, engine overhauls, exhaust system 

replacements, transmission maintenance, and oil and other 

engine fl uid changes (Reinhardt, 2005).

Further information on the options for reducing emissions 

from ground service equipment is available from the 

FAA Voluntary Airport Low Emissions (VALE) Program 

guidance document (FAA, 2004). VALE provides funding 

for low-emission vehicles, refueling and recharging 

stations, gate electrifi cation and other airport air 

quality improvements at commercial service airports in 

nonattainment and maintenance areas.6

Ground Access Vehicles

Passenger transport vehicles, including shuttle buses 

and terminal transport buses, provide an additional 

opportunity for reducing NOx and PM2.5 emissions. In 

the case of airport buses, the options are the same as 

for ground service vehicles: use a cleaner engine, use a 

cleaner fuel or add a retrofi t device. Anti-idling limits are 

another important strategy for reducing airport shuttle bus 

emissions.

Removing older engines from service and replacing them 

with new engines can reduce both NOx and PM emissions. 

EPA regulations have reduced NOx and PM2.5 emissions 

6. The Vision 100-Century of Aviation Reauthorization Act of December 12, 2003 (P.L. 108-176) directed the FAA to establish a national program to reduce airport ground emissions at commercial service airports 

located in nonattainment and maintenance areas. The VALE program 

has its origins in this law.

Table 16.4

Conversion Options

Measure Emission Reduction CostEffectiveness NOx CO VOC

CNG/LPG 

replacement 

of diesel

65% 30% 30% $1,000–$3,000 

per ton of 

VOC/CO/NOx 

combined

CNG/LPG 

conversion 

from 

gasoline

25% 45% 50-70% Cost of 

conversion 

is more than 

covered by fuel 

cost savings 

over several 

years

CNG = compressed natural gas

LPG = liquid propane gas

Source: CCAP/NESCAUM, 2003
 Chapter 16 - Airports 233

from new onroad diesel truck and bus engines by 80 

percent and 90 percent, respectively, since 1988.

In some cases, airport authorities have converted or 

replaced shuttle buses with lower-emitting, alternativefueled vehicles. The fact that airport shuttles follow a 

fi xed route and return to a central location can facilitate 

the conversion to an alternative fuel. For example, at LAX 

airport in Los Angeles, all of the courtesy shuttle fl eet 

is powered by alternative fuels (FAA, 2005). At Logan 

Airport in Boston, the Massachusetts Port Authority 

(Massport) began converting its shuttle buses in 1995. 

Now all of Massport’s fl eet of 33 airport shuttle buses use 

CNG (Massport, 2005a).

Idling diesel buses can generate excess emissions while 

waiting for passengers. In Massachusetts, anti-idling 

regulations prohibit buses from idling for a foreseeable 

period of time in excess of fi ve minutes. In 2002, EPA 

sought penalties against two shuttle bus operators at Logan 

Airport for excessive idling of diesel buses. In one case, 

a bus was observed idling for more than an hour (EPA, 

2002b).

The VALE program described above also provides funding 

for projects aimed at reducing emissions from airport 

ground access vehicles.

Chapter 13, Diesel Trucks and Buses, discusses pollution 

control strategies for buses.

Stationary Sources

A combination of on-site power generation and electricity 

from the grid supply the substantial energy needs of 

airports. Several options are available for reducing 

emissions from on-site generating facilities, including 

control technology installations, equipment upgrades or 

replacements and fuel switching. The Dallas-Fort Worth 

International Airport, for example, eliminated a substantial 

share of its stationary source NOx emissions by replacing 

two aging boilers with newer technology (Bergman, 

2005). Specifi cally, the new boilers, fi red by natural gas, 

use TODD Rapid Mix Burners in conjunction with fl ue 

gas recirculation to achieve NOx emission rates of less than 

10 ppm (Hodapp, 2005). Options for reducing emissions 

from power generating technologies are discussed in 

Chapter 5, Boiler Technologies, and Chapter 6, Industrial 

and Commercial Boilers.

Regulatory Authority

Aircraft Engines

Section 233 of the Clean Air Act preempts states from 

regulating aircraft engine emissions. States are limited to 

petitioning EPA and the U.S. Department of Transportation 

to adopt stricter emissions standards for aircraft engines 

(CCAP/NESCAUM, 2003).

Section 231 of the Clean Air Act directs EPA to issue 

emissions standards for aircraft engines to address any 

pollutant that EPA reasonably believes to endanger 

public health or welfare. Based on this authority, EPA 

in 1997 promulgated NOx and CO emissions standards 

for newly manufactured gas turbine engines consistent 

with those established by the Committee on Aviation and 

Environmental Protection (CAEP) of the International 

Civil Aviation Organization (ICAO).7 The ICAO 

establishes minimum standards that member nations are 

expected to meet, but this does not preclude a nation from 

establishing more stringent standards (CCAP/NESCAUM, 

2003). That said, national standards generally follow the 

standards adopted by the ICAO. Also, most engine models 

already meet or exceed the ICAO standards at the time 

they are adopted.

On November 9, 2005, EPA signed the Final Rulemaking 

for Aircraft Engine Emission Standards amending the 

existing NOx standards for newly certifi ed commercial 

aircraft engines (i.e., new engine models). These new 

standards are equivalent to the NOx emission standards of 

the ICAO adopted in 1999 for implementation beginning 

in 2004.8 In March 2005, the ICAO approved new NOx

standards that are 12 percent more stringent than the 

previous levels agreed to in 1999. The new standards 

would apply to newly certifi ed engines beginning in 2008. 

EPA has yet to propose standards that would align U.S. 

standards with these new international standards.

Nonroad Vehicles

As discussed in Chapter 4, the Clean Air Act gives EPA 

primary authority to regulate emissions from new nonroad 

equipment. California has authority to adopt its own 

emissions standards for some, but not all, new nonroad 

equipment, as long as the standards are at least as stringent 

as federal standards. States can adopt California or federal 

standards; at present, however, California standards 

for heavy-duty nonroad vehicles largely track federal 

standards. States are limited to California standards 

for existing nonroad vehicles. Also, the regulation 

of certain nonroad equipment that may be used at an 

airport is fully preempted under §209(e) of the Clean Air 

Act. Specifi cally, no state—including California—may 

set standards for new engines used in construction and 

farming equipment that are less than 175 horsepower in 

size.

7. ICAO is a United Nations intergovernmental body responsible for 

worldwide planning, implementation and coordination of civil aviation. CAEP coordinates the development of international standards for 

aircraft engines.

8. These standards are known as the CAEP/4 standards.
234 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

The federal emissions standards that apply to ground 

service equipment vary depending on vehicle 

characteristics (e.g., engine power rating and model year). 

In general, ground service equipment is categorized as 

nonroad equipment fueled by either gasoline or diesel 

fuel.

For regulatory purposes, nonroad engines are those used 

in mobile equipment that is not intended for use on public 

roadways. Therefore, the defi nition of “nonroad” is based 

primarily on mobility or portability. Despite the fact that 

it may be virtually identical to an engine used in a piece 

of mobile equipment, any diesel engine that will stay in 

the same place for 12 months or more—for example, to 

power a stationary generator or pump—is regulated as a 

stationary emissions source (DieselNet, 2005).

Nonroad Diesel. EPA has regulated emissions from 

new nonroad diesel engines since 1996, with progressively 

stricter standards required of later model year engines 

(the standards are known as Tier 1, Tier 2, Tier 3 and Tier 

4). The most stringent Tier 4 emissions requirements are 

being phased in beginning in 2008 on the basis of vehicle 

horsepower rating. Standards for larger nonroad diesels, 

like those used at airports, generally apply in 2011 or 

later. See Chapter 14, Nonroad Vehicles, for a complete 

discussion of EPA nonroad diesel emissions standards. 

At the same time that tighter engine emissions standards 

are being phased in, EPA regulations will be limiting 

the sulfur content of diesel fuel. As summarized in 

Table 16.6, ultra-low-sulfur diesel fuel (i.e., less than 

15 ppm sulfur) will not be required for use in nonroad 

applications until 2010. It will, however, be commercially 

available prior to this date for use in highway vehicles. 

The availability and use of low-sulfur diesel will allow 

engine manufacturers to use increasingly advanced clean 

engine technologies, facilitating compliance with the Tier 

4 emissions requirements.

Table 16.7

Standards for Large Spark Ignition Engines

Tier (year) HC + NOx CO

Tier 1 (2004) 4.0 g/kW-hr 50 g/kW-hr

Tier 2 (2007) 2.7 g/kW-hr 4.4 g/kW-hr

g/KW-hr = grams per kilowatthour

Source: EPA, 2002

Nonroad Gasoline. In 2002, EPA adopted emissions 

standards for several types of previously unregulated 

nonroad engines, including spark-ignition nonroad engines 

powered by gasoline, LPG or CNG, such as airport 

baggage tractors (EPA, 2002a). The standards apply to 

newly manufactured engines and therefore have an effect 

only as turnover occurs and older engines are replaced 

with new ones. Tier 1 standards for large spark ignition 

vehicles are effective beginning in 2004. Tier 2 standards 

are effective beginning in 2007.

Onroad Vehicles

Ground access vehicles, like ground service equipment, 

are regulated primarily by federal motor vehicle emissions 

standards, which vary according to vehicle type.

Light-Duty Vehicles. Ground access vehicles include 

passenger vehicles, such as cars and light trucks, that are 

subject to EPA or California emissions standards. 

As with new nonroad vehicles, the Clean Air Act gives 

EPA primary authority to regulate emissions from new 

onroad vehicles. California has authority to adopt its own 

emissions standards (as long as they are at least as stringent 

as federal standards), and other states can adopt either the 

California or the federal standards. Unlike the situation 

with nonroad vehicles, states and local areas do have the 

authority to set their own standards for existing onroad

vehicles. See Chapter 15, Light-Duty Cars and Trucks, for 

a more complete discussion of the standards applicable to 

light-duty vehicles.

Buses and Shuttles. As with light-duty vehicles, the 

Clean Air Act gives EPA primary authority to regulate 

emissions from new heavy-duty onroad vehicles (e.g., 

trucks and buses). California has authority to adopt its own 

emissions standards for these vehicles (as long as they are 

at least as stringent as federal standards), and other states 

can adopt either the California or the federal standards. 

California standards for new heavy-duty onroad vehicles 

largely track federal standards. States and localities are 

free to set their own standards for existing onroad vehicles. 

The federal emissions standards for buses are addressed in 

Chapter 13, Diesel Trucks and Buses.

Table 16.6

Standards for Low-Sulfur Diesel Fuel

Category Maximum Sulfur Limit (ppm)

2006 2007 2010 2012

Highway 15 15 15 15

Nonroad 3000a 500 15 15

Marine/Rail 3000a 500 500 15

a. 3000 ppm is an approximate value representing uncontrolled 

emission levels.

Source: Dieselnet, 2005
 Chapter 16 - Airports 235

General Conformity

The general conformity requirements of the Clean Air 

Act require airports in some areas to limit or offset their 

emissions under certain circumstances. Section 176(c) of 

the Clean Air Act prohibits federal entities from taking 

actions in nonattainment or maintenance areas that 

do not conform to the applicable SIP for attaining and 

maintaining National Ambient Air Quality Standards.9

If a project is forecast to generate more than a de minimis

increase in emissions and this increase is not refl ected in 

the state’s air quality plan, then the project must undergo a 

conformity assessment. As part of this process, the project 

authorities will evaluate options for mitigating the impacts 

of the project. This might include the implementation of 

mitigation measures, or the purchase of emissions offsets. 

For example, airport operators have used emissions 

reductions from ground service equipment to offset the 

emissions increases expected from airport expansions.

State and Local Policy Measures

As outlined above, a number of control options are 

available for reducing emissions from airports. The 

discussion that follows outlines policy approaches that 

state and local governments can use to mandate or 

encourage these strategies.

Aircraft Engines

Section 233 of the Clean Air Act preempts states from 

regulating aircraft emissions; however, there are some 

limited options that a state can pursue. First, states can 

petition EPA and the Department of Transportation to 

adopt stricter emissions standards for aircraft engines. 

Second, some have suggested that states may have the 

authority to regulate aircraft ground-level activities 

(e.g., limiting aircraft idling times), provided they do not 

impinge on the safety or mobility of the aircraft (CCAP/

NESCAUM, 2003). Opponents of such a policy are 

likely to challenge this authority based on a preemption 

argument.

Ground Service Equipment

Several examples exist of state environmental agencies 

negotiating voluntary agreements with airport authorities 

and air carriers to reduce emissions from ground service 

equipment. For example, the Texas Commision on 

Environmental Quality (TCEQ) negotiated a voluntary 

agreement to reduce NOx emissions in the Dallas/Fort 

Worth nonattainment area. As part of the agreement, the 

9. Transportation conformity refers to actions approved or funded by the 

Federal Highway Administration or the Federal Transit Administration. 

General conformity refers to projects approved or funded by other federal agencies. Airports are generally subject to the general conformity 

process.

air carriers agreed to reduce ground service equipment 

NOx emissions by 75 percent relative to 1996 levels 

(CCAP/NESCAUM, 2003). TCEQ also negotiated a 

voluntary agreement with Continental Airlines, Southwest 

Airlines and the City of Houston to reduce ground service 

equipment NOx emissions in the Houston-GalvestonBrazoria nonattainment area (CCAP/NESCAUM, 2003).

As part of the modernization plan for LAX, communitybased organizations negotiated an agreement to convert 

all diesel-powered ground service equipment to cleaner 

fuel alternatives. The agreement also requires all diesel 

construction equipment to be retrofi t with advanced 

pollution control systems and to use low-sulfur diesel fuel 

(LAX Coalition, 2004).

Ground Access Vehicles

In general, state and local governments have no special 

authority to regulate cars and buses at airports, beyond 

their authority (or limited authority) to regulate any 

car or bus. However, as the proprietor of an airport, a 

state does have the authority to control vehicle use at an 

airport, including idling and parking. For example, a 

state can control traffi c fl ows and the design of the airport 

to increase reliance on public transportation, thereby 

reducing personal vehicle use. A state can also require 

the use of alternative fuel or low-emitting vehicles in the 

vehicle fl eets that operate at a publicly owned airport. 

For example, the South Coast Air Quality Management 

District (AQMD) requires airport fl eet operators providing 

shuttle bus services to purchase or lease alternative-fueled 

vehicles when adding or replacing transit vehicles (South 

Coast AQMD, 2000).

Multi-Source Strategies

The airport bubble concept is a possible strategy for 

reducing overall airport emissions (Schmidt, 2005). As 

with a cap-and-trade program, the airport bubble would 

cap multiple sources of emissions. For example, the cap 

could include all of the aircraft at the airport, or aircraft, 

ground service equipment and stationary sources. The 

airport operator and other responsible entities would then 

implement a range of strategies to ensure that overall 

emissions do not exceed the cap. The cap could be 

established as an absolute limit on emissions (e.g., tons per 

year) or on a rate basis (e.g., tons per passenger).

For example, the operator of Logan Airport, Massport, 

has established a cap on airport NOx emissions: any 

emissions increases that result from airport activities must 

be offset by on-airport emissions reductions, by emissions 

reductions near the airport or by the purchase of emission 

credits. Under the auspices of the Logan Air Quality 

Initiative, Massport has committed to limiting airport NOx

emissions at or below 1999 modeled levels beginning in 

2001. In 2003, airport emissions had declined by more 
236 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

than 30 percent from the baseline levels. However, most 

of this decline is attributable to a drop in air travel, and the 

associated reduction in aircraft emissions, following the 

terrorist attacks of September 11, 2001 (Massport, 2005b).

Congress introduced legislation in 2005 to direct EPA to 

study the feasibility of applying airport bubbles as a means 

of reducing emissions (Right to Know About Airport 

Pollution Act of 2005). However, the bill was not passed 

before the 2005 session ended.

Another option for policymakers to consider is a revenueneutral fee-based system. Aircraft are subject to landing 

fees at most airports to cover the costs of airport services. 

A fee-based system, designed to reduce emissions, would 

tie the level of the fee to the emissions performance of the 

aircraft. This charge would create an economic incentive 

for air carriers to rely on lower-emitting aircraft. In order 

to encourage reductions from ground service equipment, 

the fee could be extended to cover their emissions, or the 

program could allow air carriers to offset their aircraft 

emissions with reductions from their service equipment 

fl eets. This approach has been used in Switzerland and 

Sweden (CCAP/NESCAUM, 2003).

The 2003 CCAP/NESCAUM study provides an overview 

of the legal issues that would need to be considered if a 

state were to consider imposing a bubble or landing fee 

program to reduce airport emissions.

References

Bergman, D., Dallas/Fort Worth International Airport 

Board Environmental Affairs. “Dallas-Fort Worth 

International Airport Environmental Impact Strategies,” 

The Roaring 20th Aviation Noise and Air Quality 

Symposium, February 28, 2005.

Billings, R. and R. Chang, Eastern Research Group. 

Memorandum Regarding Commercial Aircraft PM 

Emission Estimates, September 21, 2004.

Burbank-Glendale-Pasadena (BGP) Airport Authority. 

“Bob Hope Airport Begins Operation of $1.3 Million 

Electric Charging System for Airline Ground Service 

Equipment,” BGP Press Release, January 6, 2005.

Camp Dresser & McKee. “Table: 1996 Air Pollutant 

Emissions, lbs/year” (revised June 1, 2000), in: LAX 

Master Plan EIS/EIR: Air Quality Technical Report,

January 2001.

Center for Clean Air Policy and Northeast States for 

Coordinated Air Use Management (CCAP/NESCAUM). 

Controlling Airport-Related Air Pollution, June 2003. 

www.ccap.org/pdf/2003-June--Controlling_AirportRelated_Air_Pollution.pdf.

Chou Wey, C., Aviation Particulate Emissions Program, 

NASA Glenn Research Center. “Aircraft Particulate 

Emissions,” California Air Resources Board Chairman’s 

Air Pollution Seminar Series, August 22, 2005. www.arb.

ca.gov/research/seminars/cwey/cwey.htm.

Delta Airlines. “Finding Fuel Effi ciencies,” Sky Magazine,

November 2005.

DieselNet. “Nonroad Diesel Engines,” “Locomotives,” 

“Marine Diesel Engines,” Emission Standards: United 

States, accessed August 25, 2005, from: www.dieselnet.

com/standards/us.

Hodapp, R., Energy & Transportation Management, 

Dallas/Fort Worth International Airport Board. Personal 

communication with M.J. Bradley & Associates, 

December 9, 2005.

LAX Coalition for Economic, Environmental, and 

Educational Justice (LAX Coalition). Air Pollution 

Reduction and Control, November 24, 2004. www.

environmentaldefense.org/documents/4173_LAX_

AirPollutionOnePager.pdf.

Massachusetts Port Authority (Massport). Environmental 

Ground Transportation Program, accessed October 17, 

2005, from: www.massport.com/logan/airpo_gtu_afv.

html. (2005a)

Massachusetts Port Authority (Massport). “Emissions,” 

Airport Programs: Environmental, accessed October 21, 

2005, from: www.massport.com/logan/airpo_air_emiss.

html. (2005b)

Reinhardt, Karen. “Burbank: All Charged Up,” 

Ground Support Magazine, October 3, 2005. www.

groundsupportmagazine.com/publication/article.

jsp?pubId=1&id=1132.

Right to Know About Airport Pollution Act of 2005. H.R. 

3597, July 28, 2005.

Schmidt, Jake, The Center for Clean Air Policy. Aircraft 

NOx Emissions: Analysis of New Certifi cation Standard 

and Options for Introducing an Airport Bubble, February 

2005. www.ccap.org/pdf/Aircraft%20NOx%20Analysis%

20Report_x007E_FINAL.pdf.

South Coast Air Quality Management District (AQMD). 

“Commercial Airport Ground Access,” Rule 1194, October 

20, 2000. http://www.arb.ca.gov/DRDB/SC/CURHTML/

R1194.htm
 Chapter 16 - Airports 237

U.S. Department of Transportation, Federal Aviation 

Administration (FAA). CY 2003 Passenger Boarding and 

All-Cargo Data, 2003. www.faa.gov/arp/Planning/stats/

index.cfm?ARPnav=stats#cy03data.

U.S. Department of Transportation, Federal Aviation 

Administration (FAA). Voluntary Airport Low Emission 

Program: Technical Report Version 1.0 (DOT/FAA/AR04/37), September 30, 2004.

U.S. Department of Transportation, Federal Aviation 

Administration (FAA). “Appendix B: Response to 

Comments on the Final Environmental Impact Statement,” 

Record of Decision Proposed LAX Master Plan 

Improvements, May 20, 2005.

U.S. Environmental Protection Agency (EPA). Evaluation 

of Air Pollutant Emissions from Subsonic Commercial Jet 

Aircraft (EPA 420-R-99-013), April 1999. www.epa.gov/

otaq/aviation.htm.

U.S. Environmental Protection Agency (EPA). “Control 

of Air Pollution from New Motor Vehicles: HeavyDuty Engine and Vehicle Standards and Highway Diesel 

Fuel Sulfur Control Requirements; Final Rule,” Federal 

Register 66(12): 5001, January 18, 2001.

U.S. Environmental Protection Agency (EPA). “Control of 

Emissions From Nonroad Large Spark-Ignition Engines, 

and Recreational Engines (Marine and Land-Based); Final 

Rule,” Federal Register 67(217): 68241, November 8, 2002. 

(2002a)

U.S. Environmental Protection Agency (EPA). “EPA Seeks 

$60,000 From Two Bus Companies for Excessive Idling at 

Logan,” EPA Press Release, October 2, 2002. www.epa.

gov/region01/pr/2002/oct/021007.html. (2002b)

U.S. Environmental Protection Agency (EPA). “Control 

of Air Pollution From Aircraft and Aircraft Engines; 

Emission Standards and Test Procedures; Proposed Rule,” 

Federal Register 68(189): 56226, September 30, 2003.

U.S. Environmental Protection Agency (EPA). “Control of 

Emissions of Air Pollution From Nonroad Diesel Engines 

and Fuel; Final Rule,” Federal Register 69(124): 38957, 

June 29, 2004.

U.S. Environmental Protection Agency (EPA). 

Documentation for Aircraft, Commercial Marine Vessel, 

Locomotive, and Other Nonroad Components of the 

National Emissions Inventory: Volume I—Methodology,

prepared by E.H. Pechan & Associates, Inc., February 

10, 2005. ftp://ftp.epa.gov/EmisInventory/draftnei2002/

mobile/nonroad/documentation/nonroad_vol-i-rv-2.pdf. 

(2005a)

U.S. Environmental Protection Agency (EPA). “1970-2002 

Average Annual Emissions, All Criteria Pollutants,” 

National Emissions Inventory (NEI) Air Pollutant 

Emissions Trends Data, July 2005. www.epa.gov/ttn/

chief/trends/index.html. (2005b)
238 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Marine ports include a wide variety of fi ne particulate 

matter (PM2.5) and PM2.5-precursor emissions sources, 

including material-handling equipment, tractor-trailer 

trucks, locomotives, harbor vessels and ocean-going ships. 

The many sources of air pollution at a large port can 

generate signifi cant quantities of air pollution. 

There are more than 300 commercial sea and river ports in 

the U.S., which serve as transfer points for moving a wide 

variety of goods between ships and truck or rail transport 

(AAPA, 2005). 

Most ports are really a collection of multiple marine 

terminals, each with piers and docks, as well as associated 

land-side warehouses and facilities. Most ports are 

controlled by a public sector agency—often a quasi-public 

port authority with some independence—but ultimately 

the real control may rest with elected offi cials from 

surrounding jurisdictions. The port authority usually owns 

the land on which the terminal facilities sit and may also 

own and operate the terminals, thereby controlling all port 

operations. More often, the port authority simply leases 

space to private terminal operator companies, which own 

and operate the dockside equipment and storage facilities 

and are directly responsible for loading and unloading 

ships. In these circumstances, the port authority has only 

indirect control of port operations through its contractual 

relationships with the terminal operators.

The transportation of goods dominates port activities; 

however, cruise ship operations are also signifi cant at some 

ports, such as at the ports of San Francisco, California and 

New York Harbor (which serves New York City and parts 

of New Jersey). Passenger ferries can also account for 

a signifi cant share of harbor traffi c in the waters around 

some ports, such as those in Seattle, Washington and New 

York Harbor.

Marine terminals are host to a signifi cant, concentrated 

volume of truck and locomotive traffi c with its attendant 

diesel exhaust emissions. The transfer of goods from 

ships to trucks and locomotives involves a wide variety 

of mobile equipment, such as off-road cranes, fork trucks 

and port straddle carriers. Much of this equipment is 

also powered by diesel engines. Although marine ports 

Chapter 17

Marine Ports
 Chapter 17 - Marine Ports 239

are home to numerous land-side emissions sources, 

the dominant source of nitrogen oxides (NOx) and PM 

emissions are marine vessels—both the ocean-going 

ships that transport goods and the harbor craft (tug boats, 

work boats) that service them—all of which are powered 

by diesel engines. Approximately 90 percent of the PM 

emissions from these nonroad diesel engines are PM2.5

(EPA, 2005d). In addition, most marine ports also have 

stationary emissions sources (for example, from vessel 

painting or repair).

The exhaust emissions from ocean-going ships do not stop 

when the ships reach the dock. Virtually all of these large 

vessels have signifi cant “hotel” loads (for lighting, pumps, 

material-handling equipment, etc.) that must be supplied 

while the ship is docked. Typically, these loads are served 

by on-board auxiliary diesel engines coupled to generators 

that produce electricity. Some ships (particularly cruise 

ships) also use a signifi cant amount of steam for climate 

control and other services while at the dock. On-board 

diesel-fi red boilers usually produce this steam.

Since 1970, the value of trade goods shipped through 

U.S. ports has increased on average more than 10 percent 

annually (AAPA, 2005). Since 1980, the number of 

cruise passengers has grown by more than 8 percent per 

year (Cruise Lines International Association, 2005). 

Steady growth in shipping and cruise traffi c has caused 

a signifi cant increase in air emissions in and around 

the ports, and these trends are likely to continue. The 

American Association of Port Authorities projects that 

the volume of international trade through U.S. ports will 

nearly double between 2004 and 2020 (AAPA, 2005).

This chapter discusses sources of emissions at marine 

ports, relevant regulatory authority for addressing these 

sources, and control strategies available to state and local 

authorities to reduce PM2.5 and PM2.5-precursor emissions 

as they develop State Implementation Plans (SIPs).

Sector Profi le

Marine ports comprise a wide variety of emissions 

sources, including both mobile and stationary sources. 

Mobile Sources include marine vessel main 

and auxiliary engines, dockside nonroad support 

equipment (cranes, fork trucks, etc.), heavy-duty 

onroad trucks and locomotives.

Stationary Sources include maintenance 

facilities, warehouses, internal combustion engines 

and combustion turbines.

The California Air Resources Board (CARB) developed a 

PM10 emissions inventory for mobile sources at the Ports of 

Los Angeles and Long Beach as part of a draft diesel PM 

exposure assessment (CARB, 2005e). As shown in Table 

17.2, the inventory apportions total mobile source PM 

•

•

Table 17.1

Largest U.S. Marine Ports

Marine Port Rank Cargo Volumea PM2.5 Status

South Louisiana, LA 1 216.4 Attainment

Houston, TX 2 177.6 Attainment

New York / New Jersey 3 134.5 Nonattainment

Beaumont, TX 4 85.9 Attainment

New Orleans, LA 5 85.0 Attainment

Huntington, WV 6 81.1 Nonattainment

Corpus Christi, TX 7 72.0 Attainment

Long Beach, CA 8 67.9 Nonattainment

Baton Rouge, LA 9 60.6 Attainment

Plaquemines, LA 10 59.1 Attainment

Texas City, TX 11 55.2 Attainment

Los Angeles, CA 12 52.2 Nonattainment

a. Ranked by cargo volume, measured in millions of tons per year

Source: American Association of Port Authorities, 2005a; EPA, 2005a
240 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

emissions into three categories of marine vessel emissions, 

as well as three categories of land-based emissions.

As the table indicates, marine vessels account for more 

than 86 percent of all mobile source PM emissions at 

these ports. The main propulsion engines of ocean-going 

vessels transiting in and out of the port are the dominant 

source of emissions—accounting for over 50 percent 

of the total. Emissions from auxiliary engines, which 

operate while ships are docked, and from commercial 

harbor craft are also signifi cant. In terms of land-based 

mobile sources, cargo-handling equipment is the biggest 

contributor at these ports—producing almost three times 

as much PM as onroad trucks and locomotives combined. 

This information is presented for illustrative purposes—

the relative land-side emissions inventory at other ports 

may be different, depending on how much of the existing 

material-handling equipment has been electrifi ed, on 

the split between rail and truck traffi c to move goods in 

and out of the port, and other issues. However, marine 

emissions almost certainly dominate the PM emissions 

inventory at most ports.

Nationwide, marine vessels operating in ports and 

riverways are estimated to have generated 1.1 million tons 

of NOx emissions in 2002, approximately 8.9 percent of 

total national transportation-related NOx emissions. EPA 

also estimates that marine vessels produced 73,541 tons of 

direct PM2.5 emissions in 2002, approximately 16.8 percent 

of national transportation-related direct PM2.5 emissions 

(EPA, 2005d). 

Perhaps more important, over 30 of the largest U.S. ports 

are located in areas that are in nonattainment for PM2.5 or 

ozone, or both. In these locations, marine port activities 

may contribute a higher share of regional emissions than 

would be indicated by the national inventory.

For example, the total PM produced by mobile sources 

at the ports of Long Beach and Los Angeles in 2002 (see 

Table 17.2) equals approximately 25 percent of the total 

PM produced by all mobile sources in the Los Angeles 

metropolitan area (CARB, 2005c).

Efforts to reduce emissions of PM2.5 and PM2.5-precursors 

from ports should focus on reducing diesel exhaust 

emissions from marine vessels. Although states have 

limited ability to reduce emissions from ocean-going ships, 

they do have numerous opportunities to reduce emissions 

from commercial harbor craft and marine auxiliary 

engines. Efforts to reduce land-based emissions should 

focus on port-based nonroad material-handling equipment 

and on the onroad trucks and locomotives that haul goods 

into and out of the port. 

Regulatory Authority

As discussed in Chapter 4, the Clean Air Act gives EPA 

primary authority to regulate emissions from all new

vehicles, both onroad and nonroad. Generally speaking, 

California has authority to adopt its own emissions 

standards for these sources, as long as they are at least 

as stringent as federal standards. Other states can adopt 

either the California or the federal standards for new 

vehicles. Current California standards for new onroad 

trucks and most new heavy-duty nonroad equipment 

largely track federal standards. 

The rules are different for existing vehicles. All states and 

localities are free to set their own standards for existing 

onroad vehicles. The same is not true of existing nonroad

equipment—for these vehicles, the Clean Air Act allows 

California to set its own standards and other states can 

adopt these standards.

That said, the Clean Air Act fully preempts all state and 

local agencies from setting emissions standards for certain 

categories of nonroad equipment. Specifi cally, state and 

local agencies are fully preempted from setting standards 

for new engines smaller than 175 horsepower that are used 

in either (a) construction equipment or vehicles or (b) farm 

equipment or vehicles. The same preemption applies to 

new locomotives or new engines used in locomotives. 

For the emissions sources of greatest concern at marine 

ports—ocean-going ships—the reach of federal 

preemption is somewhat less clear. This is the case for 

Table 17.2

PM Emissions from Ports of Long Beach and 

Los Angeles in 2002

Source

PM Emissions

Tons % of Total

Marine Vessels

 Ocean-going vessels 942 53.5%

 Auxiliary engine-hoteling 343 19.5%

 Commercial harbor craft 244 13.9%

Subtotal – ships 1,529 86.9%

Land-based Equipment

 Cargo handling equipment 172 9.8%

 Heavy-duty trucks 41 2.3%

 Locomotives 18 1.0%

Subtotal – land based 231 13.1%

Total 1,760 100%

Source: CARB, 2005e
 Chapter 17 - Marine Ports 241

a number of reasons: (1) the majority of emissions from 

ocean-going ships calling on U.S. ports are foreignfl agged; (2) EPA regulates NOx emissions (only) from 

ships under international treaty; and (3) together with 

the Clean Air Act, the Ports and Waterways Safety Act 

regulates these vessels. That said, it can be argued that 

state authority to regulate emissions from existing oceangoing ships extends to the right to adopt any emissions 

regulations that California adopts. However, states are 

preempted from setting their own emissions standards for 

these ships.

Generally speaking, EPA has one regulatory scheme for 

onroad trucks (discussed in more detail in Chapter 13, 

Diesel Trucks and Buses) and three separate regulatory 

schemes for nonroad diesel engines (see Chapter 14, 

Nonroad Equipment): one for marine engines, one 

for locomotive engines and one for all other engines 

(agricultural, industrial, construction, material-handling, 

etc.). We discuss each of these separately. 

For regulatory purposes, nonroad engines are those used 

in mobile equipment that is not intended for use on public 

roadways. Therefore, the defi nition of “nonroad” is based 

primarily on mobility or portability. Despite the fact that 

it may be virtually identical to an engine used in a piece 

of mobile equipment, any diesel engine that will stay in 

the same place for 12 months or more—for example, to 

power a stationary generator or pump—is regulated as a 

stationary emissions source (DieselNet, 2005).

Marine Engines

For regulatory purposes, marine engines are divided into 

three categories based on size (cylinder displacement). 

The smallest, Category 1 engines, are very similar to 

the diesel engines used in onroad trucks and nonroad 

land-based vehicles. Personal vessels and some small 

commercial vessels, such as tugboats and other harbor 

craft, use these engines for propulsion power. Larger 

commercial vessels also use them as auxiliary engines. 

Category 2 engines, which are usually larger than 1,000 

horsepower, are virtually identical to locomotive engines 

and are used for propulsion and auxiliary power in large 

commercial vessels.

The largest, Category 3 marine engines, are unique. Large 

ocean vessels, such as cruise ships, freighters and tankers, 

use these engines—which range in size from 3,000 to 

100,000 horsepower—for propulsion power.

EPA fi rst regulated new marine engines beginning with 

model year 2004. The standards for Category 1 and 

2 engines are currently signifi cantly stricter than the 

standards for Category 3 engines (DieselNet, 2005). The 

international nature of ocean-going vessels complicates 

efforts to regulate their emissions absent international 

agreements. Current EPA NOx standards for Category 

3 marine engines are equivalent to the limits in Annex 

VI to the International Convention for the Prevention 

of Pollution from Ships (also known as the MARPOL 

Convention), which was negotiated under the auspices of 

the International Maritime Organization (IMO). Neither 

EPA nor the MARPOL Convention sets limits on other 

pollutants from these engines (DieselNet, 2005).

To date, EPA has not proposed tightening these emissions 

standards, as it has for other nonroad engines. However, 

the current administration, through the State Department, 

has supported MARPOL Annex VI and has indicated 

a desire to further tighten NOx standards and apply PM 

limits in future IMO negotiations (Argus, 2005).

See Chapter 14, Nonroad Equipment, for a more complete 

discussion of emissions standards for diesel marine 

engines.

Material-handling Equipment

EPA emissions standards for nonroad diesel engines have 

historically lagged behind standards for onroad engines. 

While the Agency began to regulate onroad diesel engine 

carbon monoxide (CO), NOx and hydrocarbon (HC) 

emissions in model year 1974 (PM was added in 1988), it 

has regulated emissions from nonroad diesel engines only 

since model year 1996. 

EPA has progressively tightened emissions control 

requirements for later model year nonroad engines through 

a succession of standards known as Tier 1, Tier 2, Tier 3 

and Tier 4. The Tier 4 standards take full effect in 2016 

and will introduce general parity between onroad and 

nonroad engines for the fi rst time. However, most of the 

nonroad equipment currently in use, including that used 

at most ports, is still powered by unregulated or only 

marginally regulated engines.

Chapter 14 provides a more complete discussion of 

emissions standards for nonroad diesel engines.

Locomotives

EPA fi rst regulated emissions from locomotive engines in 

2000, when a set of three standards (Tiers 0–2) became 

effective, depending on the year the engine was produced. 

Tier 0 standards apply retroactively to any engine 

manufactured between 1973 and 2001; Tier 1 applies to 

new locomotive engines produced from 2002 to 2004; 

and Tier 2 applies to new locomotive engines produced 

beginning in 2005 (EPA, 2004a).

Unlike other diesel engine emissions standards, the 

Tier 0–2 locomotive standards apply not only when the 

engine is fi rst produced, but every time the engine is re-
242 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

manufactured. This means that every locomotive engine 

built since 1973 must be upgraded to meet Tier 0 standards 

when it next has a major overhaul.

In June 2004, EPA issued an Advanced Notice of Proposed 

Rulemaking for consideration of Tier 3 standards to be 

implemented for new model year 2011 locomotive engines. 

These proposed standards would seek to reduce both PM 

and NOx emissions by 90 percent or more compared to 

the Tier 2 standards and would bring locomotive engine 

emissions roughly in line with emissions from other 

nonroad engines under the Tier 4 rules (EPA, 2004b).

Chapter 14, Nonroad Equipment, provides a more complete 

discussion of emissions standards for locomotives.

Tractor Trailer Trucks

EPA fi rst set exhaust smoke opacity standards for new 

heavy-duty onroad diesel engines beginning in model year 

1970. Starting in model year 1974, new onroad engines 

were required to meet numeric emissions limits for CO 

and NOx, plus HC. PM emissions were not regulated until 

1988. Between 1988 and 1998, the EPA limits for HC and 

CO emissions remained the same, but the allowable levels 

of both NOx and PM were each reduced in several steps. 

At 4.0 grams per brake-horsepower-hour (g/bhp-hr), the 

NOx limit in effect for model year 1998 was 63 percent 

lower than the NOx limit in effect for model year 1988, 

while the 1998 PM limit, at 0.10 g/bhp-hr, was 83 percent 

lower than the PM limit in 1988 (DieselNet, 2005).

Allowable NOx and PM standards were lowered even 

further in two subsequent rounds of EPA rulemaking. 

Current emissions limits of 0.01 g/bhp-hr for PM and 0.20 

g/bhp-hr for NOx will go into effect for new onroad heavyduty diesel engines starting with the 2007 model year 

and will be fully phased in between 2007 and 2010 on a 

percent-of-sales basis (EPA, 2001).

Chapter 13, Diesel Trucks and Buses, provides a more 

complete discussion of onroad diesel engine standards.

Stationary Sources

The federal regulations that apply to stationary combustion 

sources used at marine ports are not specifi c to the use 

of these sources in a marine setting. In addition to 

maintenance facilities and warehouses, such sources 

include internal combustion engines and combustion 

turbines (discussed in Chapter 7, Electric Generating 

Units). 

Fuel Quality

Congress has given EPA authority to regulate the quality 

of vehicle fuel and fuel additives, based on the direct 

health effects of the fuel and the effect of the fuel on the 

ability of vehicles to meet emissions standards. EPA fi rst 

regulated the sulfur content of onroad diesel fuel in 1994 

when it established a sulfur limit of 500 parts per million 

(ppm). The sulfur content of fuel used in nonroad diesels 

was unregulated. The distillate fuels currently used in 

construction and cargo handling equipment, locomotives 

and many marine vessels typically contain 3,000 ppm 

sulfur. The heavier residual oils used to power oceangoing ships can contain 50,000 ppm sulfur or more.

To allow the use of the advanced catalytic emissions 

controls that will be required to meet nonroad Tier 4 

standards and proposed Tier 3 locomotive and marine 

standards, EPA has—for the fi rst time—imposed limits 

on the allowable level of sulfur in nonroad diesel fuel. 

All nonroad diesel fuel will be limited to 500 ppm sulfur 

beginning in June 2007. A more stringent fuel sulfur limit 

of 15 ppm will be introduced for nonroad vehicles in 2010 

and for locomotives and marine distillate fuels in 2012 

(EPA, 2004a).

These sulfur limits do not apply to the residual fuels used 

in ocean-going ships, which are unregulated in the U.S. 

IMO MARPOL Annex VI establishes an international 

cap of 45,000 ppm on the sulfur content of marine residual 

fuels. This treaty also includes a mechanism to establish 

a 15,000 ppm cap in designated Sulfur Emission Control 

Areas (SECA), such as areas near coasts where additional 

emissions reductions are considered critical. While the 

U.S. has not formally ratifi ed Annex VI, the current 

administration has supported ratifi cation as well as the 

designation of coastal U.S. waters as a SECA zone (Argus, 

2005).

As discussed in Chapter 4, The Clean Air Act, if EPA 

has regulated a fuel characteristic or component, states 

other than California may not adopt either their own or 

California’s regulation—they must follow the federal 

regulation. The only exception to this is the situation in 

which the Administrator fi nds that state regulation is 

Table 17.3

Standards for Low-Sulfur Diesel Fuel

Category Maximum Sulfur Limit (ppm)

2006 2007 2010 2012

Highway 15 15 15 15

Nonroad 3000a 500 15 15

Marine/rail 3000a 500 500 15

Ocean ships 45,000

a. 3000 ppm is an approximate value representing uncontrolled 

emission levels.

Source: EPA, 2001, 2004b
 Chapter 17 - Marine Ports 243

necessary for achieving the National Ambient Air Quality 

Standards (NAAQS). On the other hand, California may 

adopt its own fuel regulations.

Other Regulations: California

Under the Clean Air Act, California can set its own 

emissions standards for both new and existing onroad 

vehicles, as well as for new and existing nonroad 

vehicles (with the exception of certain small vehicles and 

locomotives). However, California has, for the most part, 

adopted EPA regulations for new onroad and nonroad 

diesel equipment with only slight modifi cations.

California also has its own regulations for onroad and 

nonroad diesel fuel. Under the California rules, nonroad 

diesel fuel sold in California for other than locomotive 

or marine applications will be limited to 15 ppm sulfur 

beginning in 2006, four years earlier than the nonroad 

diesel sold in the rest of the country (CARB, 2004).

Chapters 13 and 14 provide a more complete discussion of 

California diesel engine emissions standards. 

State Authority

States are restricted to implementing California or federal 

standards for new onroad and nonroad engines. However, 

states and local areas have authority to adopt their own 

standards for existing onroad engines. For existing 

nonroad engines, states are limited to federal or California 

standards. In fact, even the authority to adopt California 

regulations for these sources is largely theoretical at this 

point, since California has just begun to adopt mandatory 

retrofi t requirements for certain types of nonroad 

equipment, beginning with portable engines. However, 

none of the limitations on state and local authority to 

impose standards prohibit the adoption of voluntary 

programs or the incorporation of retrofi t requirements into 

government contracts for construction or other services. 

Finally, as noted above, all states—including California—

are barred from imposing their own limits on certain small 

nonroad equipment and on locomotives.

Emissions Control Opportunities

Many of the control technologies that are and will be 

applied to new onroad and nonroad diesel engines to 

comply with current and future EPA regulations can also 

be applied to existing marine and land-side engines and 

vehicles used in and around ports. There are three main 

approaches for reducing emissions from a diesel vehicle 

or fl eet: use a cleaner engine, use a cleaner fuel or add a 

retrofi t device.

Changes to equipment or operational practices that reduce 

total fuel usage from port vehicles and equipment can also 

reduce total emissions and save money in the bargain.

Use a Cleaner Engine

New diesel engines certifi ed to stricter EPA standards 

produce 30–60 percent less NOx and PM than the 

unregulated engines built as recently as a few years ago. 

These reductions have come from changes in diesel engine 

design, most notably better control of lubrication oil, higher 

fuel injection pressures and the addition of electronic 

fuel control. In some cases—particularly with respect to 

Tier 3 nonroad engines with electronic fuel control—the 

emissions reductions have been accompanied by improved 

fuel effi ciency. Removing older engines from service and 

replacing them with new engines can therefore have a large 

positive emissions benefi t. 

For most older vehicles, it is more cost-effective to retire 

the vehicle itself. However, for some specialty port 

equipment where the engine represents a relatively small 

percentage of the vehicle’s total value, “repowering” old 

equipment with a new engine may a better option. This 

approach has proved to be particularly cost-effective for 

Category 1 marine engines larger than 600 horsepower 

where improvements in fuel economy from the new 

engine can partially offset the cost. These engines provide 

propulsion power in some tugs and work boats used in 

marine ports. 

For some nonroad port material-handling equipment, 

it may be possible to achieve even greater reductions 

by repowering with an onroad engine certifi ed to lower 

emissions standards than new nonroad engines. 

In limited cases it is also possible to cost-effectively 

rebuild and modify existing engines to incorporate more 

modern design elements and equipment, thus reducing 

their emissions. In addition to improved fuel injector 

designs, some of the cleaner engine and after-treatment 

technologies that are applicable specifi cally to marine 

engines include exhaust gas recirculation, water injection 

and sea water scrubbers. 

Use a Cleaner Fuel

Some alternative formulations of diesel fuel produce 

lower emissions of NOx and/or PM in existing engines 

compared to standard onroad or nonroad diesel fuel. The 

most common of these cleaner diesel fuels are described in 

Chapter 12, Diesel Engine Technologies.

Cleaner onroad ultra-low-sulfur diesel fuel could also 

be introduced in ports for use by marine and nonroad 

material-handling equipment before it becomes mandatory 

in 2012. This onroad fuel will have signifi cantly less 

sulfur than the nonroad fuel available between now and 
244 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

2012 and will produce slightly lower PM emissions when 

used in typical nonroad engines. Use of lower sulfur fuel 

will also allow port equipment to be retrofi tted with more 

aggressive after-treatment technologies, resulting in even 

greater PM reductions (see Chapter 12). After 2012, all 

nonroad fuel will be required to have the same sulfur level 

as onroad fuel.

Heavy-duty engines that operate on natural gas are 

also available for onroad trucks and buses and produce 

signifi cantly lower PM emissions than current diesel 

engines. Natural gas engines have PM emissions 

equivalent to the 2007 EPA PM standards for new onroad 

diesel engines. These natural gas engines are also certifi ed 

to produce 30–50 percent lower NOx emissions than the 

current EPA NOx standards for new onroad diesels. While 

it is technically possible to modify existing diesel engines 

to operate on natural gas, it is generally preferred to use a 

purpose-built natural gas engine (ICCT, 2005). 

Whether using a purpose-built or retrofi t engine, natural 

gas conversions require that the vehicle fuel system be 

modifi ed extensively to store either high-pressure gaseous 

or low-temperature liquefi ed natural gas (LNG) fuel in lieu 

of liquid diesel fuel; in addition, LNG or high-pressure 

natural gas fueling stations must be installed. Given the 

current limited availability of natural gas fueling stations, 

conversion to natural gas is most appropriate for fl eet 

vehicles that are centrally fueled at a fi xed site and that 

operate within a limited geographic area. These criteria 

are often met in the case of land-side material-handling 

equipment used in ports. For example, the Port of Los 

Angeles has recently announced a goal to shift from diesel 

power to the use of natural gas engines for cargo-handling 

equipment (Port of Los Angeles, 2005d).

Liquid petroleum gas (LPG), like natural gas, can also be 

used in specially designed engines to power equipment 

that might otherwise use diesel fuel; it too produces lower 

PM and NOx emissions. LPG is not typically used in the 

U.S. for onroad trucks or large nonroad equipment, but 

small and medium-sized forklifts are available with LPG 

engines.

In the category of cleaner fuels, electricity can also play 

a role in ports. Depending on the fuel used for electricity 

generation, net NOx reductions associated with converting 

nonroad equipment from diesel to electric power can be 

40–80 percent (EPA, 2004c, DieselNet, 2005). While 

the dirtiest coal- and oil-burning power plants could 

actually produce greater PM emissions than nonroad 

diesel equipment, the actual grid mix in many parts of 

the country would produce a net PM reduction of 25–95 

percent (EPA, 1998; DieselNet, 2005). In either case, the 

localized benefi ts are even greater, since no electric motors 

emit PM or NOx at the point of use.

Unlike onroad vehicles, which typically travel long 

distances in a day, many of the cranes used to unload 

ships in port are essentially stationary. For this stationary 

equipment, the necessary electric power can be pulled 

directly from the electric grid, without the need for 

batteries on the vehicle and periodic charging. Ports from 

New York to Seattle have been replacing diesel-powered 

cranes with electric cranes.

Other land-side material-handling equipment in the port 

operates within a very limited geographic area for its 

entire life. Thus, the range limitations associated with 

battery-powered mobile electric vehicles are not a barrier. 

In particular, small and medium-sized forklifts are 

commercially available with electric drives. 

Emissions generated by the auxiliary engines of oceangoing ships while they are docked are a signifi cant part of 

the inventory of most ports. For some of these ships, landside electric power can be used to supply the necessary 

ship-side hotel loads in lieu of on-board auxiliary engines 

(“cold ironing”), resulting in signifi cant emissions 

reductions. 

Add a Retrofi t Device

As described in Chapter 12, Diesel Engine Technologies, 

there are a number of EPA- and CARB-verifi ed retrofi t 

technologies that can be installed on existing diesel 

vehicles to reduce emissions. Most of these are “aftertreatment” devices that are installed in the exhaust system 

to clean up the exhaust after it has left the engine, rather 

than reducing the emissions produced by the engine. 

Most of these technologies rely on some kind of catalytic 

process and can reduce either PM or NOx emissions, but 

not both simultaneously. However, discrete technologies 

can be combined into a single commercial product to yield 

simultaneous NOx and PM reductions.

The three main approaches to reducing emissions from 

diesel vehicles are not mutually exclusive. In fact, some 

commercially available retrofi t devices work better in 

conjunction with, or even require the use of, an alternative 

diesel fuel. Products are also available that combine 

engine modifi cations with retrofi t devices, while engine 

repowering can always be combined with after-treatment 

control retrofi ts to reduce emissions even further. 

Fuel Economy Improvements

As discussed above, some new nonroad engines are both 

cleaner and more fuel effi cient than older engines, so that 

repowering to reduce emissions can provide additional 

benefi ts based on fuel savings. This is especially true for 

engines available to repower marine harbor craft such as 

tugboats, as well as some cargo handling equipment.
 Chapter 17 - Marine Ports 245

larger and more costly the control device.

Replacement engines for material-handling equipment 

can cost $30,000 or more installed, and Category 1 marine 

engines can cost more than $100,000 (TCEQ, 2004). Given 

this expense, voluntary emissions reduction programs are 

more effective when accompanied by a funding source to 

offset the cost to the equipment owner.

Programs to offset the cost of emissions controls can take 

many forms: for example, they can provide a tax reduction 

or incentive, or rebate some or all of the cost of taking a 

specifi c action. The most common emissions reduction 

incentive programs for the type of diesel equipment 

typically found in ports are grant programs.

The two largest grant programs of this type currently 

operating are California’s Carl Moyer Memorial Air 

Quality Standards Program (Carl Moyer) and the Texas 

Emissions Reduction Program (TERP). Since its 

inception in 1998, Carl Moyer has provided $184 million 

in grant funding for various emissions reduction projects 

throughout California (CARB, 2003). Approximately 30 

percent of these funds went to projects to reduce emissions 

from nonroad diesel equipment that might be found in 

ports, including marine vessels, forklifts and locomotives 

(CARB, 2005a).

Since 2001, TERP has provided $82 million in grants to 

replace 98 locomotives and retrofi t six yard switchers and 

$11 million to repower 89 and retrofi t six marine engines 

in the 41 Texas counties designated as nonattainment areas 

(TCEQ, 2004).

In recent years EPA has awarded demonstration grants 

under its National Clean Diesel Campaign. The most 

recent grants were announced in February and October 

2005, with a total of $2.6 million going to 26 projects 

across the country (EPA, 2005d). The projects include 

retrofi ts of rubber-tired gantry cranes and port straddle 

carriers. The program requires matching funds.

Over the last four years the Puget Sound Clean Air 

Agency in Seattle, Washington has sponsored and funded 

approximately 3,000 retrofi ts of both onroad vehicles and 

nonroad equipment, including port material-handling 

equipment. It has also (a) helped fund a pilot program to 

use ultra-low-sulfur onroad diesel fuel in a Washington 

State ferry running between the U.S. and Canada and (b) 

established—in cooperation with a number of private and 

public partners—a shore power facility (see below) for 

Princess Cruise Line vessels calling at the Port of Seattle. 

This facility has been operating since the summer of 2005. 

The Puget Sound Clean Air Agency Diesel Solutions 

program is voluntary and incentive-based (Puget Sound 

CAA, 2005).

In addition, operational changes at ports may reduce total 

fuel consumption by vehicles and equipment within the 

port, thus reducing total emissions. Trucks entering the 

port to drop off or pick up cargo often end up queuing 

for long periods of time waiting for an open gate. While 

waiting, drivers often leave their vehicles idling, which 

wastes fuel and increases total emissions. Methods that 

can reduce queuing and attendant idling include better 

layout of terminal gates and staging areas, the use of gate 

appointment scheduling systems, expansion of port hours 

with incentives for off-peak delivery and pick-up, and 

the use of common pools of dreyage trucks by multiple 

terminal operators. Voluntary or mandatory idling 

restrictions for waiting trucks can also help (see Chapter 

13, Diesel Trucks and Buses).

Many goods today are moved as “containerized” cargo 

in standardized metal containers that go from truck 

or locomotive to ship, and vice-versa, without being 

unloaded. In many ports, the movement and storage of 

these containers dominate operations. Optimal terminal 

layout and better tracking and management of individual 

containers using information technology can minimize the 

use of nonroad material-handling equipment and resultant 

emissions.

In some cases greater use of rail (instead of trucks) to move 

goods in and out of ports can also reduce total fuel use and 

emissions within the port, while also reducing truck traffi c 

and congestion in surrounding communities.

State and Local Policy Measures

Programs that encourage or mandate the retirement or 

replacement of older diesel equipment, the use of cleaner 

fuels or electrifi cation, or the retrofi t of older equipment 

with emissions control devices can have a large impact on 

air quality. These programs provide the most signifi cant 

opportunity for states to control and reduce PM and NOx

emissions from equipment used in ports.

Whether these programs are voluntary or mandatory, their 

common focus is on the application of new technology to 

existing onroad and nonroad diesel equipment. Programs 

that result in reduced fuel usage will also reduce PM and 

NOx emissions.

Voluntary Retrofi t Programs

Replacing vehicles and engines, using alternative fuels 

and installing retrofi t devices can be expensive. The 

Manufacturers of Emission Controls Association estimates 

that retrofi t PM control devices for Class 8 trucks cost 

between $1,000 and $10,000 per vehicle, depending on the 

type of retrofi t device being installed (MECA, 2000); NOx

control devices can cost as much as $20,000 or more for 

the same vehicles. In general, the larger the engine, the 
246 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

A number of states have also used funds from 

environmental enforcement actions to fund diesel retrofi t 

projects. For example, as part of a 2003 consent decree, 

the Port of Los Angeles created a $20 million Air Quality 

Mitigation Program that provides fi nancial incentives to 

port area businesses to clean up their operations (Port of 

Los Angeles, 2005a). Funds from this program have been 

used to retrofi t onroad trucks used in the port, as well as to 

retrofi t and repower marine engines.

Chapter 13 provides a more detailed discussion of funding 

mechanisms for clean air grant programs.

One potential impediment to the adoption of voluntary 

programs by ports is concern about the effect on future port 

expansion activities that may be subject to the conformity 

requirements of the Clean Air Act (see Chapter 4). Given 

rising cargo volumes across the country, many ports face 

pressure to expand their operations. In order to expand, 

ports may need to identify emissions reduction credits for 

use in meeting conformity requirements. Some ports may 

be unwilling to take actions to reduce existing emissions 

unless the reductions can be used for conformity purposes 

in the context of a later expansion project. A method for 

ports to “bank” site-specifi c credits for later use might 

provide an incentive for ports to take early action. 

Despite this problem, conformity requirements can 

contribute substantially to overall emissions reductions. 

For example, in order to offset increased NOx emissions 

from a 10-year harbor dredging project in New York 

Harbor, the Port Authority of New York and New Jersey 

implemented a Harbor Air Mitigation Plan (HAMP) 

that included retrofi tting Staten Island Ferries with 

selective catalytic reduction (SCR) technology, as well 

as repowering tug boats. While the NOx from dredging 

activities will peak at approximately 450 tons per year (ton/

year), the HAMP strategies will produce 800–1,000 ton/

year of NOx offsets beginning in 2006. After the dredging 

project is over, the implemented projects will reduce total 

NOx emissions in the harbor by up to 1,000 ton/year (EPA, 

2005b). 

Mandatory Retrofi t Programs

As stated previously, states other than California are 

limited to adopting California standards for existing 

nonroad equipment. In 2004, CARB adopted mandatory 

retrofi t requirements for the portable diesel engines used 

in agricultural pumps, airport ground-support equipment, 

oil drilling rigs, portable generators and other nonroad 

equipment in California. The rule requires stepped 

reductions in PM emissions from these engines to reach a 

95 percent reduction level by 2020 and is likely applicable 

to some diesel sources in ports (CARB, 2005b). In 

addition, CARB in December 2005 released a Draft 

Emission Reduction Plan for Ports and International Goods 

Movement in California. This plan anticipates future 

action by CARB to mandate the use of cleaner fuels and 

retrofi ts of marine harbor craft and port-based materialhandling equipment (CARB, 2005d). Other states can 

adopt the current CARB requirements for portable engines 

as well as any other rules applicable to port-based nonroad 

engines that California adopts in the future.

Indirect mandates imposed through contractual 

requirements may be more practical in some situations. 

This approach can be implemented by the port authority 

through contract arrangements with the companies that 

operate the terminals. These arrangements will have to 

be negotiated as modifi cations to existing contracts or will 

require the expiration of current contracts.

For example, the Port of Long Beach Authority is drafting 

a tariff proposal that will require all tenants in the port to 

develop and implement a plan to signifi cantly reduce PM 

and NOx emissions from their operations by 2008. The 

Authority envisions that the contractual requirements will 

allow tenants fl exibility in achieving the reductions.

As part of a ten-year contract extension for railroad 

switching services within the ports, the Ports of Long 

Beach and Los Angeles will require Pacifi c Harbor Line to 

replace its existing fl eet of 16 locomotives—some of which 

are more than 50 years old—with cleaner equipment. The 

new locomotives will include engines that burn emulsifi ed 

diesel fuel and exceed EPA Tier 2 locomotive emissions 

standards. Under the agreement, Pacifi c Harbor will 

also acquire one locomotive fueled by natural gas and 

one with a hybrid diesel/battery-electric drive system. 

Pacifi c Harbor will also test diesel oxidation catalysts; if 

successful, they will be retrofi t on all its new locomotives. 

A Carl Moyer grant will partially fund the program, with 

Pacifi c Harbor and the ports sharing remaining costs (Port 

of Long Beach, 2005).

For port authorities that directly own and operate terminal 

equipment, administrative policies that require retrofi ts, 

retirement/repowering or fuel switching could complement 

policies for tenant equipment.

Idle Reduction 

Trucks often queue at marine terminals and idle while 

waiting to pick up or deliver goods. Unnecessary idling 

wastes fuel and increases emissions of NOx and PM. EPA 

estimates that an idling Class 8 truck uses, on average, 0.82 

gallons of diesel fuel per hour and produces 144 grams per 

hour of NOx emissions (EPA, 2002).

In order to reduce or eliminate unnecessary truck idling, 

approximately 26 states and governmental subdivisions 

have enacted laws that restrict the idling of diesel vehicles 

(ATRI, 2004). Typically, these laws set a maximum 
 Chapter 17 - Marine Ports 247

reduce PM emissions; diesel oxidation catalysts do not 

work well if fuel sulfur is greater than 500 ppm, while the 

most effective diesel particulate fi lters require fuel with no 

more than 50 ppm sulfur (see Chapter 12, Diesel Engine 

Technologies). 

Although EPA regulations will require reduced sulfur 

levels in nonroad diesel fuel, implementation dates lag 

those for onroad diesel fuel. Beginning in June 2007, when 

EPA will require nonroad diesel and marine distillate fuels 

to have no more than 500 ppm sulfur, diesel oxidation 

catalyst retrofi ts will become practical on a wide range of 

nonroad equipment used in ports, including marine harbor 

craft and material-handling equipment. Retrofi ts with the 

more effective diesel particulate fi lters will not be possible 

until nonroad diesel fuel sulfur is reduced to below 50 

ppm, which, under current EPA rules, will not happen 

until 2010 for most nonroad equipment and until 2012 for 

locomotives and marine distillate fuels. Retrofi t programs 

for nonroad equipment will not be effective prior to these 

dates without the use of onroad diesel fuel in the retrofi t 

nonroad equipment. This is why the Puget Sound Clean 

Air Agency has helped fund a pilot program to use ultralow-sulfur onroad diesel fuel in a Washington State ferry.

California has mandated that all nonroad diesel fuel other 

than fuel for locomotives and marine applications have no 

more than 15 ppm sulfur beginning in 2006—four years 

earlier than the EPA mandates. Other states can adopt 

these California fuel regulations—but only if EPA fi nds 

that such action is necessary for achieving the NAAQS. 

Given the very high sulfur content of the residual fuel 

oil used to power ocean-going ships, very few retrofi t 

technologies will be effective on the Category 3 marine 

engines used for propulsion in these vessels. A switch to 

distillate fuels would itself reduce PM and sulfur dioxide 

(SO2) emissions, while opening up greater opportunities 

for pollution control retrofi ts. However, this would require 

modifi cations to the fuel systems on these engines, and 

would dramatically increase fuel costs for vessel owners. 

A more practical approach would be to require the use 

of reduced-sulfur onroad or nonroad diesel fuel in the 

auxiliary engines that provide power while vessels are 

docked in port. For example, the Port of San Francisco is 

providing monetary incentives to offset the cost to cruise 

ship operators of using lower sulfur fuels while their ships 

are in port. EPA provided $100,000 toward this program 

through the West Coast Collaborative and other project 

partners are providing $141,000 in matching funds (West 

Coast Collaborative, 2005a)

Ocean-Going Ships

As noted previously, many marine vessels operate 

auxiliary engines while in port to power their “hotel” 

allowable idling period, anywhere from 2–15 minutes, 

with fi nes for violations. Port authorities could implement 

similar idling restrictions.

Idling laws usually provide an exemption for idling in 

traffi c, as well as for idling necessary to ensure safe 

operation of the vehicle—for example, to maintain the air 

pressure in the air brake system. Recognizing that diesel 

engines can be diffi cult to start in cold conditions, these 

laws also often provide an exemption to allow additional 

idling below a specifi c ambient temperature, such as 32 or 

20 degrees Fahrenheit. Some also provide an exemption 

to maintain power for heating, cooling or auxiliary 

equipment.

Switcher yard locomotives also generally idle for long 

periods of time—an issue in ports that load cargo directly 

from ships to rail. These locomotives are allowed to idle 

to maintain engine oil and coolant temperatures, or to 

provide a relatively small amount of electrical power for 

auxiliary equipment. They often idle primarily because 

of the operator’s perception that it is easier than shutting 

down and restarting. Argonne National Laboratory 

estimates that a typical switcher yard locomotive idles up 

to 75 percent of the time and that idling accounts for 27 

percent of its total fuel use (Argonne, 2005). 

As discussed in Chapter 12, Diesel Engine Technologies, 

a number of systems can be installed to (a) provide 

the necessary electrical power for auxiliary loads on 

locomotives or (b) monitor various engine parameters 

and automatically shut down the engine when idling is 

unnecessary and restart it as required. EPA’s review of 

available systems of this type indicates that they cost 

between $4,000 and $50,000 to install on a locomotive, 

depending on the type of device used. Given the amount 

of fuel that can be saved by reducing or eliminating idling, 

many of these systems nevertheless have payback periods 

as short as 6–20 months (Gaines, 2005).

Port authorities could encourage or mandate the use of 

technologies to reduce or eliminate unnecessary idling in 

the same way that they encourage or mandate equipment 

retirement, engine repowering, control device retrofi ts 

and fuel switching. EPA has issued guidance to states for 

taking credit for the benefi ts of an idle reduction program 

(EPA, 2004d).

See Chapter 14, Nonroad Equipment, for examples of 

projects to address locomotive idling.

Nonroad Diesel Fuel

At approximately 3,000 ppm, the current sulfur content 

of nonroad diesel fuel impedes the use of effective retrofi t 

emissions controls on marine and other nonroad engines. 

Sulfur interferes with the catalytic processes used to 
248 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

loads (i.e., onboard electrical equipment and pumps). 

For certain types of ships—especially cruise ships, 

refrigerated cargo vessels and some tankers—the electrical 

loads being supplied can be signifi cant: anywhere from 

600 to 7,000 kilowatts. In addition, some types of vessels 

spend signifi cant time in port; cruise ships typically spend 

12–24 hours docked while exchanging passengers at 

the beginning and end of each trip. Some cargo vessels, 

meanwhile, take 30–100 hours or more to unload (Port of 

Long Beach, 2004).

The combination of high onboard power demand and long 

port calls results in signifi cant in-port exhaust emissions 

from ship auxiliary engines. For example, an analysis of 

port calls at the Port of Long Beach in southern California 

determined that a single ship that regularly calls at the port 

produces, on an annual basis, over 85 tons of NOx, 9 tons 

of PM and 79 tons of SO2 while at the pier (Port of Long 

Beach, 2004). 

One approach to reducing these emissions is to provide 

electrical power from the land-side electrical grid to supply 

in-port hotel loads, instead of using the onboard auxiliary 

diesel engines. This approach was pioneered by the Navy 

and is called “cold ironing.” 

Cold ironing requires signifi cant modifi cations to both the 

affected ships and the land-side infrastructure. The fi rst 

cold ironing project in the U.S. was completed in 2001 in 

Juneau, Alaska. It involved the installation of necessary 

shore-side equipment and retrofi t of four cruise ships 

owned by Princess Cruises. Installing the shore-side 

equipment cost $4.7 million; ship retrofi t costs averaged 

$500,000 per vessel (Port of Long Beach, 2004). Princess 

Cruises is also participating in a shore power project at 

Terminal 30 in the Port of Seattle. This project is expected 

to reduce annual PM and NOx emissions within the port by 

2 tons and 14 tons, respectively (McLerran, 2005). 

Given the low cost of marine distillate fuels, the typical 

cost of electricity supplied from the land-side grid is 

slightly higher than the cost of fuel for onboard electricity 

generation. 

Because of the expense involved, cold ironing is not a 

cost-effective strategy for every ship. Nonetheless, the air 

quality benefi ts of this approach can be signifi cant and can 

also be cost-effective if applied to ships with a signifi cant 

hotel load and many long port calls. For example, a study 

by the Port of Long Beach showed that the use of shore 

power to supply hotel loads to only three ships could 

reduce annual in-port emissions by almost 500 ton/year, 

at a cost of $11,000 per ton or less (Port of Long Beach, 

2004).

The Port of Los Angeles has developed specifi cations for 

both the ship-side and shore-side equipment necessary 

for cold ironing, which it calls Alternative Marine Power 

(AMP). In June 2004, the port opened the fi rst U.S. 

container berth equipped to provide shore power (Berth 

100 at the China Shipping Terminal); two months later, 

the Port of Los Angeles hosted the fi rst ship capable of 

accepting this power (the NYK Atlas). The port has plans 

to install AMP equipment at additional terminals (Port of 

Los Angeles, 2005c).

Other actions that can be taken to reduce ship emissions in 

and around ports include the use of lower sulfur diesel fuel 

in auxiliary engines while in port, as discussed above, and 

reducing ship speeds near the coast. Because ships that 

operate at lower speeds have lower emissions, both the Port 

of Long Beach and the Port of Los Angeles implemented 

a Voluntary Commercial Ship Speed Reduction Program 

in 2001, which encourages vessels to travel at or below 12 

knots within 20 miles of the coast. The ports estimate that 

nearly 70 percent of shipping lines currently calling at the 

port participate in the program and that NOx emissions 

from these ships have been reduced by more than 1 ton per 

day (Port of Los Angeles, 2005b).

Operational Changes

Marine ports are complicated commercial enterprises, 

typically with many different players trying to move 

many different types of cargo among a number of 

different transportation modes on a daily basis. Given this 

complexity, port operations are likely to contain numerous 

ineffi ciencies that lead to long wait times for individual 

trucks as well as wasteful use of dreyage trucks and 

material-handling equipment. Operational changes that 

reduce truck queuing and idling, such as extending port 

hours and providing incentives for off-peak delivery, and 

better use of information technology to track containers 

and schedule pick-ups and deliveries, may contribute to 

increased effi ciency and reduced fuel usage.

For example, the Georgia Ports Authority gave all members 

of the port/terminal community real-time, round-the-clock 

access to transaction information via a web portal. This 

system has reduced gate processing times by reducing the 

number of “trouble transactions” precipitated by outdated 

or inaccurate data. As a result it has all but eliminated 

truck queuing outside terminal gates and has reduced truck 

turn-around time by 30 percent; the Authority estimates 

that this has reduced NOx emissions by half a ton on peak 

days (EPA, 2005b, 2005c). 

A common practice at many ports is for each terminal 

operator to own its own fl eet of dreyage trucks (or chassis), 

which can only be used to move containers that belong 

to that company. Chassis switching by drivers moving 

containers from multiple operators can add up to an hour 

per trip and contributes to congestion on port roadways. 

In October 2004, the Port of Virginia became the fi rst U.S. 
 Chapter 17 - Marine Ports 249

port to require that all of its terminal operators participate 

in a common chassis pool, meaning that any vehicle can be 

used to move any container. This has reduced the number 

of individual trucks stored and used within the port by 

20 percent—a reduction of 5,000 chassis. Local drivers 

who had previously only been able to move two to three 

containers per shift are now completing up to ten moves 

a day, increasing their income and improving service to 

customers while reducing total fuel use and emissions 

within the port (EPA, 2005c).

Increased use of rail transport to move goods in and out 

of ports may also contribute to net emissions reductions, 

while also reducing the use of mobile diesel-powered 

material-handling equipment in favor of electric-powered 

stationary cranes. Increased use of rail transport could 

also provide ancillary benefi ts to nearby communities 

by reducing truck traffi c and congestion in local 

neighborhoods. However, this approach is likely to require 

signifi cant investments in new rail infrastructure and may 

be constrained by the layout of existing port facilities and 

the availability of appropriate rights of way.

Many of the operational changes that will help to reduce 

emissions will also save time and money for terminal 

operators as well as their customers. Nonetheless, the 

changes may also entail signifi cant up-front expense and 

there is likely to be signifi cant competition for the capital 

funding that might pay for them. 

To facilitate the implementation of some of these strategies, 

it might be appropriate to include them for eligibility in 

a clean air grant program—in the same way that vehicle 

retrofi ts, engine repowering and fuel switching are eligible. 

In light of the fact that these changes might ultimately save 

the terminal operators money, a low-interest revolving loan 

program (discussed in Chapter 14, Nonroad Equipment) 

might be even more appropriate.

Additionally, in the same way that the “bubble” concept is 

applicable to airports, it is appropriate for consideration in 

the marine port context. The bubble would cap multiple 

sources of emissions, such as commercial harbor craft, 

cargo handling equipment and stationary sources. A 

range of strategies would ensure that overall emissions did 

not exceed the cap, with the cap established as an absolute 

limit on emissions (e.g., tons per year) or on a rate basis 

(e.g., tons per passenger).

References

American Association of Port Authorities (AAPA). 

America’s Ports: Gateways to Global Trade, accessed 

October 25, 2005, from: www.aapa-ports.org.

American Association of Port Authorities (AAPA). U.S. 

Port Ranking by Cargo Volume, 2002, accessed October 

26, 2005, from: www.aapa-ports.org/pdf/2002_US_

Cargo_Rank.pdf. (2005a)

American Transportation Research Institute (ATRI). 

Compendium of Idling Regulations, September 2004. 

http//atri-online.org/research/results/idling_chart.pdf.

Argonne National Laboratory, Transportation and 

Technology R&D Center. Reducing Heavy Vehicle Idling,

accessed October 4, 2005, from: www.transportation.anl.

gov/research/technology-analysis/idling.htm.

Argus Air Daily. White House Backs Maritime Pollution 

Treaty 12(189): 8, September 30, 2005.

California Environmental Protection Agency, Air 

Resources Board (CARB). The Carl Moyer Memorial 

Air Quality Standards Attainment Program Guidelines

(Approved Revision 2003), September 30, 2003.

California Environmental Protection Agency, Air 

Resources Board (CARB). “The California Diesel Fuel 

Regulations,” California Code of Regulation, Title 13, 

§§2289-2295, August 14, 2004.

California Environmental Protection Agency, Air 

Resources Board (CARB). Carl Moyer Program Update, 

January 20, 2005. www.arb.ca.gov/msprog/carl_moyer_

board_presentation_1_20_05.pdf. (2005a)

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Resources Board (CARB). Facts About California’s 

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Resources Board (CARB). Draft Diesel Particulate Matter 

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International Association, accessed October 26, 2005, 

from: www.cruising.org.
250 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

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eduction.

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Gas as a Transportation Fuel: Best Practices for Achieving 

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& Associates, 2005. www.cleantransportcouncil.org/

documents/NGV_ICCT_2005.pdf.

Manufacturers of Emissions Controls Association 

(MECA). Independent Cost Survey for Emissions Control 

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Ports—Replacement of Locomotive Fleet to Signifi cantly 

Improve Air Quality,” Port of Long Beach Press Release,

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to Eliminate More than 430 Tons of Air Pollutants,” Port of 

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Months,” Port of Los Angeles Press Release, August 17, 

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dieselsolutions/ds-overview.shtml. 

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Volume I, 1998. www.epa.gov/ttn/chief/ap42/index.html.

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and Commercially Available Idle-Reducing Devices 

(EPA420-R-02-025), October 2002. (2002)

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Emissions of Air Pollution from Nonroad Diesel Engines 

and Fuel; Final Rule,” Federal Register 69(124), June 29, 

2004. (2004a)

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Emissions of Air Pollution from New Locomotive Engines 

and New Marine Compression Ignition Engines Less than 

30 Liters per Cylinder; Proposed Rule,” Federal Register

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USA, Case Studies, accessed December 12, 2005, from: 

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 Chapter 17 - Marine Ports 251

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12, 2005, from: www.epa.gov/smartway/swresources.htm. 

(2005c)

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(2005d)

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252 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

In aggregate, households in the U.S. consume large 

amounts of fossil fuel-based energy—both on-site and 

indirectly, through the use of electricity. According to the 

Energy Information Administration (EIA), the residential 

sector was responsible for 21 quadrillion British thermal 

units (Btus) or “quads” of energy consumption in 2004—

21 percent of total U.S. energy consumption (EIA, 2005). 

Common uses of energy associated with this sector include 

space heating, water heating, air conditioning, lighting, 

refrigeration and cooking.

The residential sector produces fi ne particulate matter 

(PM2.5) and PM2.5-precursor emissions on-site from the 

direct consumption of fuels—such as natural gas, liquefi ed 

propane gas, kerosene, fuel oil, coal and wood—primarily 

for space heating and water heating. Furnaces, boilers, hot 

water tanks, wood stoves and other equipment produce 

PM2.5 and PM2.5-precursor emissions to varying degrees, 

depending on the fuel consumed and the technology used. 

This chapter discusses strategies for reducing the direct 

emissions generated by these sources. 

The residential sector is also heavily reliant on electricity 

to meet its energy needs. According to EIA, the 

residential sector was responsible for 36 percent of U.S. 

electricity consumption in 2004 (EIA, 2005). As a result, 

a substantial share of emissions associated with residential 

sector energy consumption occur off-site, at fossil-fi red 

power plants. Chapter 7, Electric Generating Units, 

discusses strategies for reducing power plant emissions 

directly. This chapter reviews a number of strategies for 

reducing household electricity consumption to further 

reduce PM2.5 and PM2.5-precursor emissions from power 

plants.

Sector Profi le

Every four years, EIA conducts a national survey of 

household energy use known as the Residential Energy 

Consumption Survey. According to this survey, in 

2001, nearly half (47 percent) of all household energy 

Chapter 18

Residential Fuel 

Combustion and Electricity Use
 Chapter 18 - Residential Fuel Combustion and Electricity Use 253

consumption was devoted to home heating (EIA, 2001).1

Another 17 percent was used for hot water heating, 6 

percent was used for electric air conditioning and 5 percent 

was used for refrigeration. The remaining 24 percent was 

used for lighting and to power other appliances. Some 

regions of the country, such as the Northeast, devote a 

greater share of energy use to home heating (58 percent) 

because of their colder climate.2

 This distribution of 

energy use does not, however, refl ect the full energy 

impact of household electricity use. A comprehensive 

accounting that includes generation losses at the power 

plants supplying electricity and the line losses involved 

in delivering power across the electricity grid would 

nearly double the energy use attributed to residential 

sector electric use. This means that energy effi ciency 

improvements in appliances, lighting and air conditioning 

will have almost twice as much impact on overall energy 

consumption, compared to non-electric energy use, as 

Figure 18.1 suggests.

According to EIA, the three most common energy 

sources for home heating in the U.S. are natural gas, 

serving 50 percent of households; electricity, serving 36 

percent of households; and fuel oil, serving 7 percent of 

households (EIA, 2001). The U.S. Census Bureau’s more 

recent American Community Survey reports a similar 

distribution; specifi cally, it found that nearly 62 million 

1. This includes natural gas, fuel oil, kerosene, liquefi ed petroleum gas 

and electricity use. It does not include wood use on-site or fuel consumption at the power plants supplying the electricity.

2. The Residential Energy Consumption Survey is a national survey 

that collects information on residential energy use. In the most recent 

survey, conducted in 2001, data were collected from 4,822 households 

statistically selected to represent the 107 million housing units in the 

U.S. Data are available for four census regions and nine census divisions. State-level data are available for the four most populated states 

(California, Texas, New York and Florida). www.eia.doe.gov/emeu/

recs/contents.html.

homes (57 percent) used natural gas or liquefi ed petroleum 

gas as their heating fuel in 2003. The second most popular 

home heating source was electricity, used by 33.9 million 

homes (31.3 percent). According to this survey, only 8.6 

percent of households nationwide used fuel oil or kerosene 

as their primary heating fuel (U.S. Census Bureau, 2004).3

Wood is generally not the primary source of energy for 

home heating in U.S. households. However, widespread 

use of wood stoves and fi replaces in some areas is an 

important contributor to ambient levels of particulate 

matter. In certain winter pollution episodes, more than half 

of the atmospheric PM2.5 concentration in a local area can 

be attributed to wood smoke (Schauer, 2000). According 

to EPA, there are 40–45 million wood burning appliances 

in the U.S., 15 million of which are wood stoves, either 

free standing or fi replace inserts (Brockman, 2005a). 

Many of the wood stoves that are in regular use in the U.S. 

were installed prior to the federal emissions performance 

standards adopted in 1988.

There are more than 27 million fi replaces in U.S. homes 

that are used for supplemental heat, aesthetics or as a 

primary heat source (Houck, 2000). In general, there 

are two types of fi replaces: manufactured metal and site 

masonry fi replaces. In 1997, approximately 400,000 

factory-built metal fi replaces were sold in the U.S. These 

fi replaces are designed to last 40 years or more. Masonry 

fi replaces can last indefi nitely.

According to the Hearth, Patio and Barbecue Association, 

as many as 100,000 homes across North America heat with 

an outdoor wood-burning furnace, a vast increase from the 

2004 fi gure of 78,000 (Russell, 2005).

3. The results of the American Community Survey are available at the 

state and county level. www.census.gov/Press-Release/www/releases/

archives/american_community_survey_acs/003053.html.

Fig. 18.1 U.S. Residential Energy Use, 2001

Source: U.S. EIA, 2001

Fig. 18.2 U.S. Residential Electricity End Uses

Source: U.S. EIA, 2001
254 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Natural gas is also the dominant energy source used 

for water heating, serving 54 percent of households. 

Electricity is second, serving 39 percent of households, 

and fuel oil is third, serving 4 percent of households (EIA, 

2001).

Electricity dominates as the energy source for other major 

household functions, including refrigeration and lighting. 

Major uses of electricity in U.S. homes are air conditioning, 

space heating, refrigeration, lighting, water heating and a 

broad category of uses that we designate as “other” (e.g., 

televisions, computers, small appliances). Figure 18.2 

provides a national break-out of household electricity use 

by end-use category.

Residential fuel combustion produces PM2.5 and PM2.5-

precursor emissions to varying degrees, depending 

on the fuel consumed and the technology used. Table 

18.1 presents national emissions estimates for primary 

household energy consumption by fuel type. Wood 

combustion is the dominant source of direct PM2.5

emissions within the residential sector. (Wood stoves and 

fi replaces also produce a host of hazardous air pollutants 

including benzene, toluene and polycyclic organic matter.) 

Oil is the leading source of direct (on-site) sulfur dioxide 

(SO2) emissions within the sector, refl ecting the higher 

sulfur content of home heating oil relative to natural gas 

and wood. Residential coal consumption accounts for an 

estimated 26 percent of the sector’s direct SO2 emissions. 

The majority of homes that use coal for home heating are 

located in just a few states: Pennsylvania (37 percent), 

Kentucky (7 percent), Indiana (7 percent) and New York 

(7 percent) (U.S. Census Bureau, 2004). Natural gas 

produces the largest share of residential nitrogen oxides 

(NOx) emissions, in part because of its widespread use.

In addition to direct emissions, the residential sector is also 

responsible for a substantial share of U.S. electricity use. 

According to EIA, the residential sector was responsible for 

36 percent of U.S. electricity consumption in 2004 (EIA, 

2005). Table 18.1 provides an estimate of the indirect 

emissions attributable to residential electricity use.4

Finally, many households also engage in open burning for 

the disposal of leaves, tree branches and yard trimmings. 

Open burning produces PM2.5 emissions, as well as a host 

of other pollutants, depending on the materials burned. 

Burning household trash presents a special concern 

because of the air toxics generated (EPA, 2003). Research 

by EPA suggests that a family of four burning its household 

4. These fi gures were calculated by attributing 36 percent of the electric 

power sector’s PM2.5, SO2 and NOx emissions to the residential sector. 

The actual electricity-related emissions attributable to the residential 

sector would vary based on the load profi le of household electricity use 

(i.e., when homes are consuming electricity and which power plants are 

serving load at these times); however, we consider our more simplifi ed 

approach to be a reasonable proxy.

Table 18.1

Residential Fuel Combustion Emissions, 1999

Fuel Type PM2.5 SO2 NOx

Source 

Category

Tons/Year Percent 

of Sector 

Emissions

Tons/Year Percent 

of Sector 

Emissions

Tons/Year Percent 

of Sector 

Emissions

Natural gas 

(including 

liquefi ed 

petroleum gas)

23,981 4% 1,703 1% 258,968 65%

Oil (primarily 

distillate)

6,229 1% 124,706 66% 52,693 13%

Wood 419,247 67% 5,696 3% 45,402 11%

Coal 5,147 1% 51,555 27% 7,290 2%

Open burning 

(household and 

yard waste)

 174,936 28% 5,107 3% 33,461 8%

Total direct 

emissions

629,540 100% 188,767 100% 397,814 100%

Indirect emissions 

(electricity use)

223,492 NA 4,530,064 NA 2,058,692 NA

Source: EPA, 2005a
 Chapter 18 - Residential Fuel Combustion and Electricity Use 255

wastes on-site will generate as much or more dioxin than 

a full-scale, 200 ton-per-day municipal waste incinerator 

(Western Lake Superior Sanitary District, 2005).

Emissions Control Opportunities

A multitude of technologies and conservation measures are 

available for reducing the air pollution emissions associated 

with residential energy use. The discussion that follows 

addresses many of these options and identifi es resources 

for obtaining further information. The discussion focuses 

on the major uses of energy in the home: space heating 

(including wood stoves and fi replaces), water heating and 

powering various household appliances. To touch on all 

of the options available is beyond the scope of this report. 

For example, we do not discuss options for enhancing 

building effi ciency through improved insulation and 

windows. However, we do address many of the options 

that we believe offer signifi cant potential for reducing 

residential energy use and emissions.

Space Heating

In many parts of the U.S., space heating is the largest user 

of energy in the residential sector, accounting for nearly 

half (47 percent) of all household energy consumption in 

2001 (EIA, 2001). Space heating is also one of the most 

costly items in the household energy budget, particularly 

as natural gas and fuel oil prices have continued to rise.

As indicated in the sector profi le above, natural gas is 

the most widely used home heating fuel. In 2003, nearly 

62 million homes (57 percent) relied on natural gas or 

liquefi ed petroleum gas as their heating fuel, 33.9 million 

homes (31.3 percent) relied on electricity and 8.6 percent 

of households nationwide relied on fuel oil and kerosene 

(U.S. Census Bureau, 2004).

Furnaces, boilers and electric resistance heaters supply 

most of the heating in homes today. In homes heated 

by natural gas, furnaces are the most common heating 

system—67 percent of gas-heated homes use central 

furnaces, with the remainder of homes split among hot 

water (hydronic) systems, direct-heating furnaces and 

room heaters. In homes heated by electricity, the primary 

heating equipment is split nearly evenly among three 

categories: electric furnaces, heat pumps and baseboard 

heaters. In oil-heated homes, 41 percent use furnaces 

and 55 percent use boilers (E Source, 1997). Options for 

reducing the energy use and emissions associated with 

these systems include fuel switching, installing add-on 

controls to make existing systems more energy effi cient, 

replacing older systems with newer, lower-emitting and 

higher-effi ciency models, and replacing conventional 

technologies with alternatives, such as solar energy space 

heating technologies or geothermal heat pumps.

Gas Furnaces. NOx is the major pollutants of concern 

produced by a natural gas-fi red residential furnace. 

Emissions rates depend primarily on the peak temperature 

within the combustion chamber, oxygen concentrations 

and the amount of time that the combustion air is exposed 

to peak temperatures. As these three factors increase, 

NOx emissions levels increase. Natural gas combustion 

can also produce particulate emissions; however—because 

natural gas is a gaseous fuel—PM emissions are typically 

low and emitted particles are generally less than one 

micrometer (μm) in size. Increased PM emissions may 

result from poor air/fuel mixing or maintenance problems. 

Natural gas combustion can also produce SO2 emissions 

Table 18.2

Emissions from Natural Gas- and Oil-Fired Residential Furnaces

Source Category PM (lb/MMBtu) SO2 (lb/MMBtu) NOx (lb/MMBtu)

Natural gas furnacea

(<0.3 106 Btu/hr heat input)

0.007-0.011b,c 0.0006 0.092

#2 fuel oil furnaced

(2,500 ppm sulfur)

0.012 0.25 0.13

#2 fuel oil furnaced

(500 ppm sulfur)

0.012 0.051 0.13

#2 fuel oil furnaced

(15 ppm sulfur)

0.012 0.0015 0.13

a. Emissions factors were converted to an energy basis (lb/MMBtu) by using a heating value of 1,020 MMBtu/106 standard cubic feet (scf).

b. Assumed to be less than 1.0 μm in diameter.

c. Lower PM value from AP-42 Chapter 1: External Combustion Sources, Section 1.4 Natural Gas Combustion, Supplement D, July 1998. 

Higher value from Questar Gas, Environmental Information, http://www.questargas.com/brochures/environmental.pdf.

d. All values from AP-42 Chapter 1: External Combustion Sources, Section 1.3 Fuel Oil Combustion. Tables 1.3-1 and 1.3-2, September 

1998. Emissions factors were converted from lb/103

 gallon using a conversion factor of 140 MMBtu/103 gallon.
256 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

because a sulfur-containing mercaptan is added to the fuel 

to permit leak detection. Emissions rates for a residential 

gas furnace are presented in Table 18.2.

Home Oil Use. Heating oil, also known as No. 2 fuel 

oil, is much like diesel fuel, with at least one important 

distinction. Heating oil contains between 2,000 and 2,500 

parts per million (ppm) sulfur (Bookhart, 2003). By 

comparison, sulfur levels in onroad diesel fuel are limited 

by regulation to less than 500 ppm, as discussed in Chapter 

13.

Oil heat is used in more than 8 million homes, 6.3 million 

(78 percent) of which are in the Northeast (Bookhart, 

2003). Residential oil use produces PM2.5, SO2 and NOx

emissions; however, SO2 is the primary pollutant of 

concern. (The emissions rates of a residential oil furnace 

are presented in Table 18.2.) Virtually all (99 percent) of 

the sulfur in fuel oil is oxidized to SO2 when combusted, 

and thus there is a direct linear relationship between oil 

sulfur content and SO2 emissions from residential boilers 

(Batey, 2002). 

The most effective strategy for reducing SO2 emissions 

from residential oil use is lowering the sulfur content 

of heating oil. Currently in the U.S., heating oil for 

residential use has an average sulfur content of about 0.20–

0.25 percent. Switching to low sulfur content fuel could 

eliminate 75–80 percent of the SO2 emissions generated 

by residential oil heating systems, as well as 80 percent of 

PM2.5 emissions (McDonald, 2003). 

The American Society for Testing and Materials (ASTM), 

an international voluntary standards development 

organization, has approved a Low-Sulfur No. 2 Heating 

Oil specifi cation. Also, the Oilheat Manufacturers 

Association has been promoting low-sulfur heating oil, 

both to improve air quality and to reduce equipment 

maintenance costs (NORA, 2005). Low-sulfur heating 

oil reduces the level of residue build-up on the surfaces of 

boilers and furnaces, improving equipment performance 

and reducing maintenance costs. According to the Center 

for Clean Air Policy (CCAP), low-sulfur fuel oil costs 

about $0.01/gallon more than conventional fuel oil and 

would add roughly $8.65 a year to a typical customer’s 

annual fuel bill, based on average annual oil consumption 

of 865 gallons per year (CCAP, 2005).

Technology options are also available that can improve 

the effi ciency of oil-fi red boilers and furnaces, such as 

high static fl ame retention burners. Since 1992, new oil 

furnaces have been required to meet a minimum energy 

effi ciency standard of 78 percent, while new oil boilers 

have been required to meet an effi ciency standard of 80 

percent (DOE, 1989). Earlier model boilers and furnaces 

are still in service, however, and can have effi ciencies as 

low as 60 percent or lower. A recent analysis estimates 

that approximately 5 percent of furnaces and 22 percent 

of boilers in the 15 states that consume the most home 

heating oil are operating at or below 60 percent effi ciency 

(CCAP, 2005).5

 

The National Oilheat Research Alliance (NORA) has 

produced a guide for oil heat technicians that outlines 

options for low- and no-cost techniques to conserve 

heating fuel: Effi cient Oilheat: An Energy Conservation 

Guide.

Wood Stoves and Fireplaces. There are three 

basic strategies for reducing PM2.5 and PM2.5-precursor 

emissions from wood stoves and fi replaces: (1) reducing 

or eliminating the burning of wood where less polluting 

alternatives (e.g., natural gas-fi red units) are available; (2) 

relying on higher-effi ciency, lower-polluting wood stove 

technology; and (3) adopting good burning techniques 

(e.g., using properly sized and properly seasoned wood).

As discussed in more detail below, EPA established smoke 

emissions limits for new wood stoves in the late 1980s. As 

a result, all new wood stoves and fi replace inserts must be 

certifi ed to a maximum limit of 7.5 grams of smoke per 

hour. (Fireplaces and outdoor wood boilers are exempt 

from regulation.) The EPA standards have not only 

improved the emissions performance of new wood stoves, 

but have also improved their fuel effi ciency.

Wood stove manufacturers use two basic strategies to 

meet the EPA standards: catalytic and non-catalytic 

combustion (Wood Heat Organization, 2005). With 

catalytic combustion, the exhaust from the stove passes 

through a specially coated ceramic honeycomb inside the 

stove, where the smoke gases and particles ignite and burn. 

The on-going performance of the stove depends on the 

maintenance and replacement of the catalytic honeycomb, 

5. These 15 states include Connecticut, Maine, Maryland, Massachusetts, Minnesota, New Hampshire, New Jersey, New York, North 

Carolina, Pennsylvania, Rhode Island, Vermont, Virginia, Ohio and 

Wisconsin.

Fig. 18.3 Wood Stove Technologies

Source: EPA 
 Chapter 18 - Residential Fuel Combustion and Electricity Use 257

Source: Spitzer, 2005b, Houck, 2000, and Houck, 1998.

Fig. 18.4 PM Emissions Rates (grams/hour)

72 g/hr Outdoor wood boiler

60 g/hr Fireplace (cordwood)

19 g/hr Conventional wood stove

16 g/hr Fireplace (manufactured log)

 6 g/hr EPA-certifi ed wood stove

 2.7 g/hr Pellet stove

 0.07 g/hr Oil furnace

 0.04 g/hr Gas furnace

which can degrade in as little as two years without regular 

cleaning and maintenance (Wood Heat Organization, 

2005). 

Non-catalytic stoves rely on the design characteristics of 

the unit to allow complete combustion of the wood. These 

design features include fi rebox insulation, a large baffl e 

to produce a longer, hotter gas fl ow path, and pre-heated 

combustion air introduced through small holes above the 

fuel in the fi rebox. Non-catalytic stoves have no catalyst 

to replace; however, some of the internal components of 

a non-catalytic stove need replacement as they degrade 

from high temperatures. Most available stoves are noncatalytic. Wood pellet stoves, which burn sawdust and 

other wood products pressed into small pellets, have 

grown in popularity and produce lower emissions than a 

conventional stove. Some pellet stoves can also burn dried 

corn kernels.

Some of alternative fuel options for wood stoves include 

manufactured fi relogs and natural gas fi replaces, as well 

as the alternative heating devices described above (e.g., 

gas furnaces). (See Figure 18.4 for a comparison of 

average PM gram per hour emissions rates for various 

home heating devices.) Gas fi replaces are becoming 

increasingly popular, with newer models that mimic the 

look of a real wood fi re. These self-contained units can be 

installed into an existing masonry fi replace. Manufactured 

fi relogs, made from wax and sawdust for open-hearth 

fi replaces, can reduce PM2.5 emissions. Studies suggest 

that manufactured fi relogs can reduce PM2.5 emissions by 

an average of 69 percent, relative to burning cordwood in a 

fi replace (Houck, 2000).

As indicated in Table 18.1, wood stoves and fi replaces 

are the leading sources of PM2.5 emissions within the 

residential buildings sector. Table 18.3 presents PM2.5

emissions factors for a conventional wood stove, catalytic 

EPA-certifi ed stove non-catalytic EPA-certifi ed stove, 

and pellet stove. Data come from two sources: (1) EPA’s 

AP-42 emissions factor handbook and (2) a recent study 

prepared for the Hearth, Patio and Barbecue Association 

(Houck, 2005a).6

The benefi ts of replacing a conventional stove with an 

EPA-certifi ed unit can be estimated based on the emissions 

factors presented in Table 18.3, but should also refl ect the 

higher effi ciency of the newer technology. A modern stove 

provides higher heating value for the same quantity of 

wood burned. An EPA-certifi ed catalytic or non-catalytic 

stove is about 10 percent more effi cient than a conventional 

wood stove, and a pellet stove is 20 percent more effi cient 

(Houck, 2005a). Higher-effi ciency, cleaner-burning stoves 

also reduce creosote build-up and may reduce the number 

of chimney cleanings required.

The average cost of a new stove, including the cost 

associated with a chimney upgrade, is estimated at $2,500 

6. In the Hearth, Patio and Barbecue Association study, the authors 

adjust the average emissions factors for conventional stoves because 

they assume lower burn rates than EPA assumed in its AP-42 Emission 

Factor Handbook. This results in higher emissions. Also, the study suggests lower average emissions factors for EPA-certifi ed stoves, based on 

research demonstrating that the emissions performance of wood stoves 

has improved since the earliest models were produced in the early 1990s. 

Earlier models were used as the basis for the AP-42 emissions factors 

for EPA-certifi ed stoves. EPA is currently in the midst of re-evaluating the AP-42 emissions factors for wood stoves, which may shed some 

light on the differences in estimated emissions rates between these two 

sources (Wood, 2005).

Table 18.3

Wood Stove PM2.5 Emissions Factors

Stove Type AP-42 PM2.5

Emissions 

Factors (lb/ton)

Houck PM2.5

Emissions 

Factors (lb/ton)

Conventional 

wood stove

30.6 66.8

Catalytic EPAcertifi ed wood 

stove

16.2 15.1

Non-catalytic 

EPA-certifi ed 

wood stove

14.6 11.7

Pellet stove 8.8 2.5

Source: EPA, 1996; Houck, 2005a
258 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

(Houck, 2005b). Assuming that a conventional wood stove 

with a PM2.5 emissions factor of 66.8 pounds per ton (lb/

ton) is replaced by a non-catalytic wood stove with a PM2.5

emissions factor of 11.7 lb/ton, PM2.5 emissions would be 

reduced by roughly 140 lb per heating season.7

According to EPA, preliminary estimates suggest that 

changing out wood stoves can be a cost-effective option 

for reducing PM2.5 emissions. EPA estimates that this 

approach can cost less than $2,000 per ton of PM2.5

reduced (Houck, 2005b). The feasibility of purchasing 

and installing a new wood stove is a separate issue, which 

depends on the income of the household. As discussed 

later in this chapter, grants have been used to fund the 

replacement of older stoves for low-income families.

The Mid-Atlantic Regional Air Management Association 

has published a document, Emissions Inventory 

Improvement Program (EIIP): Residential Wood 

Combustion Coordination Project, as an information 

resource for state, local and regional organizations that 

are planning or conducting residential wood combustion 

surveys. EPA recommends the use of surveys for the 

development of residential wood combustion emissions 

inventories.

Water Heating

Water heating is one of the largest uses of energy in 

the residential sector; it accounts for 17 percent of 

direct (primary) household energy use according to the 

Residential Energy Consumption Survey (2001). 

In the residential sector, there are generally four 

destination points or end uses for hot water: faucets, 

showers, dishwashers and washing machines. Strategies 

are available that address these end uses, as well as the 

water heating systems themselves. Just some of the 

measures that are available for reducing the energy use 

and emissions associated with water heating are discussed 

here.

Reducing Hot Water Use. Installing low-fl ow 

showerheads and faucet aerators can save signifi cant 

amounts of hot water. Low-fl ow showerheads can reduce 

hot water consumption for bathing by 30 percent. A top 

quality, low-fl ow showerhead will cost $10–$20 and 

can pay for itself in energy saved within four months. 

Repairing leaks in faucets and showers will also save hot 

water. 

The biggest cost of operating a dishwasher stems from the 

7. This example calculation also assumes an annual average cord usage 

of 1.75 cords per stove (adjusting the amount of wood used by the new 

stove to refl ect its increased effi ciency), and a cord-to-mass conversion 

factor of 1.4 tons per cord, which is reported to be typical of wood used 

in the eastern United States (Houck, 2005b).

energy required to heat the water before it ever makes it 

to the machine. An ENERGY STAR-qualifi ed dishwasher 

will use less hot water than a conventional dishwasher 

(generally manufactured before 1994). 

As with dishwashers, much of the cost—up to 90 percent—

of operating clothes washing machines is associated with 

the energy needed to heat the water. Unlike dishwashers, 

clothes washers do not require a minimum temperature 

for optimum cleaning. Either cold or warm water can be 

used for washing most laundry loads; cold water is always 

suffi cient for rinsing. Laundry detergents are currently 

available that are specially formulated for washing in 

cold water (Procter & Gamble, 2005). Most full-sized 

ENERGY STAR-qualifi ed washers use 18–25 gallons 

of water per load, compared to the 40 gallons used by a 

standard machine. 

Reducing Heating Load. Lowering the thermostat 

setting on a water heater can reduce energy use without 

any loss of convenience. Although some manufacturers 

set water heaters at 140 degrees Fahrenheit (°F) (or 60 

degrees Celsius (°C)), 120°F (48.9°C) is satisfactory for 

most household needs. For every 10°F (5.6°C) reduction in 

water temperature, water-heating energy consumption can 

be reduced 3–5 percent.

Hot water tanks operate constantly to keep hot water 

available on demand. Timers are available that can 

automatically turn hot water heaters on and off, reducing 

unnecessary energy use, especially in older units. A timer 

costs approximately $30 and is easily installed. Timers for 

gas water heaters are less cost-effective than those designed 

for electric water heaters. Also, a timer will produce only 

limited energy savings when used with modern water 

heaters that have relatively low standby losses.

Insulating an older water heater storage tank is a fairly 

simple and inexpensive improvement that can help 

maintain the water temperature at the thermostat setting. 

Newer models of water heaters are well insulated and 

do not need an added layer. Hot water pipes can also be 

insulated to reduce heat loss, particularly in unheated 

areas.

Installing High Effi ciency Water Heaters. Replacing 

an older water heater with a new, high-effi ciency model 

can reduce energy use between 10 and 50 percent. Some 

of the technologies that are available for reducing energy 

use include higher-effi ciency, conventional gas and 

electric storage tank water heaters, as well as alternative 

technologies that tend to be less widely used, such as 

tankless water heaters, heat pump water heaters and solar 

water heaters. 

More stringent federal effi ciency standards for 

conventional water heaters were recently introduced, 
 Chapter 18 - Residential Fuel Combustion and Electricity Use 259

Table 18.4

Products Subject to Existing Federal Effi ciency Standards

National Appliance Energy 

Conservation Act of 1987 and 1988 Energy Policy Act of 1992 Energy Policy Act of 2005

Refrigerator-freezers Fluorescent lamps Traffi c lights and pedestrian signals

Freezers Incandescent refl ector lamps Building transformers

Room air conditioners Electric motors (1-200 hp) Torchiere lamps

Central air conditioners and heat pumps Commercial packaged air 

conditioners and heat pumps

Compact fl uorescent lamps and 

fl uorescent lamp ballasts

Furnaces, boilers and water heaters Commercial furnaces and boilers Residential ceiling fans and ceiling-fan 

light kits

Direct-fi red space heaters Commercial water heaters Residential dehumidifi ers

Clothes washers and dryers Showerheads Commercial refrigerators and freezers

Dishwashers Faucets and aerators Commercial unit heaters and large 

commercial air-conditioners

Ranges and ovens Toilets Commercial ice makers and commercial 

clothes washers

Pool heaters Distribution transformersa Vending machinesa

Fluorescent lamp ballasts Small electric motors (<1 hp)a Pre-rinse spray valves (typically found in 

dishwashers)

Televisionsa High-intensity discharge lampsa Exit signs

a. Specifi c standards were not set in the legislation, rather DOE was instructed to investigate whether standards are technically feasible 

and economically justifi ed and to adopt standards in response to their fi ndings.

Source: Nadel, 2005; Edison Electric Institute, 2005

effective January 20, 2004 (EPA, 2001a). The previous 

standards had been in place since 1991. Water heaters are 

not currently assigned ENERGY STAR designations. In 

January 2004, the Department of Energy (DOE) concluded 

that it would not be worthwhile to develop ENERGY 

STAR designations for conventional water heaters, since 

the differences between the best-performing products and 

those just meeting the minimum federal standard were 

deemed too small to justify an ENERGY STAR rating 

(Karney, 2004). For example, a 50-gallon electric tank 

water heater is required to achieve a minimum energy 

factor of 0.904 (Karney, 2004). The best performing 

model has a factor of 0.95. 

According to DOE, heat pump, solar and tankless gas 

water heaters produce signifi cant energy savings relative 

to conventional products. However, the Department 

again concluded that ENERGY STAR designations are 

not appropriate at this time because the payback periods 

for these technologies are too long (3.6–19 years) relative 

to other ENERGY STAR products (Karney, 2004). Also, 

DOE suggests that the infrastructure to sell and service 

some of these products is not fully developed.

Regulatory Authority

DOE is responsible for establishing minimum energy 

effi ciency standards for several categories of home 

appliances, including refrigerators, freezers, air 

conditioners, fl uorescent lamp ballasts, clothes dryers, 

clothes washers, dishwashers, kitchen ranges and ovens, 

and water heaters. These standards apply to newly 

manufactured products only and prohibit the production 

or import of appliances and other products less effi cient 

than the minimum requirements. Current standards 

are available from DOE’s Appliances and Commercial 
260 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

label on a wood heater indicates that it meets the EPA 

emissions standards. A consumer information label, which 

specifi es the emissions rate, the heating range of the wood 

heater and overall effi ciency, is also required.

The Energy Policy Act of 2005 provides a rebate to 

consumers who purchase a renewable energy appliance 

with a thermal effi ciency rating of 75 percent, including 

wood and wood pellet stoves. The bill provides a 25 

percent rebate, capped at $3,000. DOE will be responsible 

for implementing the program.

Congress has also considered legislation that would 

provide a $500 tax credit for households in PM10 or PM2.5

nonattainment areas that replace an old wood stove with 

an EPA-certifi ed model (Wood Stove Replacement Act of 

2005).

State and Local Policy Measures

A multitude of options are available for states seeking to 

reduce PM2.5 and PM2.5-precursor emissions associated 

with household energy use. Because of the number of 

measures available, we address only some of the options 

that are believed to offer signifi cant potential for reducing 

emissions.

NOx Emissions Standards for Gas Furnaces

In California, several air districts, including the South 

Coast Air Quality Management District (AQMD), the 

Bay Area AQMD and the San Diego County Air Pollution 

Control District, have adopted NOx emissions standards 

regulating natural gas-fi red central furnaces. The South 

Coast AQMD was the fi rst to adopt a NOx emissions 

standard for natural gas-fi red central furnaces. The 

South Coast AQMD adopted its standard in 1978. The 

standard applies to central furnaces rated at less than 

175,000 Btu per hour. Because the standards apply only 

to new furnaces, emissions will decline gradually as older, 

higher-emitting units are replaced and new homes are 

equipped with certifi ed models. In 2005, the San Joaquin 

Valley Unifi ed Air Pollution Control District (UAPCD) 

in California adopted a NOx emissions standard for new 

residential furnaces identical to the South Coast AQMD 

standard: 0.093 lb/MMBtu of heat output or 55 ppm NOx

at 3 percent oxygen stack gas by volume (dry). According 

to District staff, the difference between the cost of 

manufacturing a low-NOx emitting unit and a conventional 

model is minimal (San Joaquin Valley UAPCD, 2005a).

The South Coast AQMD has not updated its NOx standard 

for natural gas-fi red central furnaces since 1978. States 

should consider whether a more stringent standard is 

achievable based on new or existing technology. For 

example, researchers at the Lawrence Berkeley National 

Laboratory have developed a technology, known as 

Equipment Standards Program website.8

Energy effi ciency standards were fi rst adopted at the state 

level when California passed its 1974 appliance effi ciency 

laws for refrigerators, freezers and air conditioners. Other 

states, including Florida, Massachusetts and New York, 

followed California’s lead by adopting standards for various 

products in the early and mid-1980s. In response to the 

resulting patchwork of state energy effi ciency standards, 

Congress adopted national standards that preempted 

individual state requirements. Congress adopted national 

standards in 1987 (under the National Appliance Energy 

Conservation Act (NAECA) of 1987), in 1988 (when 

NAECA was expanded to include fl uorescent ballasts), in 

1992 (under the Energy Policy Act of 1992), and in 2005 

(under the Energy Policy Act of 2005). The Energy Policy 

Act of 2005 establishes energy effi ciency standards for 

several product categories, including dehumidifi ers, ceiling 

fans and various other products. At the time the Act was 

adopted, Arizona, California, Connecticut, Maryland 

and New Jersey had already adopted similar effi ciency 

standards. The products covered by federal effi ciency 

standards are summarized in Table 18.4.

Other policy measures that have been used to promote 

household energy effi ciency—apart from effi ciency 

standards—include education programs, rebate programs 

and building code requirements. For example, the Energy 

Policy Act of 2005 provides limited tax credits for energysaving home improvements implemented in 2006 and 

2007. Eligible projects include installing insulation, new 

exterior windows (capped at $200), solar hot water systems 

and other home improvements. The bill also includes 

tax credits for contractors who build energy-effi cient 

homes and for manufacturers who make energy-effi cient 

appliances.

In 1988, EPA established New Source Performance 

Standards (NSPS) for wood stoves, requiring all new 

wood stoves sold in the U.S. to be certifi ed to meet certain 

particulate emissions limits by 1992 (EPA, 1988).9

 EPA’s 

mandatory smoke emissions limit for wood stoves is 7.5 

grams of smoke per hour (g/hr) for non-catalytic stoves 

and 4.1 g/hr for catalytic stoves.10 Some newer stoves 

have certifi ed emissions in the range of 1–4 g/hr. This 

compares to an average emissions rate of approximately 

42 g/hr for earlier models. Fireplaces and outdoor wood 

boilers are exempt from regulation under the NSPS. 

According to EPA, there are approximately ten million 

wood stoves in active use in the U.S., 75 percent of which 

are pre-NSPS stoves (Brockman, 2005b). A permanent 

8. www.eere.energy.gov/buildings/appliance_standards/.

9. EPA’s website provides a listing of EPA-certifi ed wood stoves: www.

epa.gov/compliance/resources/publications/monitoring/.

10. Wood stoves offered for sale in the state of Washington must meet a 

particulate emissions limit of 4.5 g/hr for non-catalytic wood stoves and 

2.1 g/hr for catalytic wood stoves.
 Chapter 18 - Residential Fuel Combustion and Electricity Use 261

Resources available from 

EPA’s wood stove and fi replace website:

How-To Guide for Implementing a Wood 

Stove Changeout Campaign

Fact Sheet: Burn Clean-Hot Tips for a Better 

Fire

Guidance for Supplemental Environmental 

Projects

Public education materials on clean burning 

wood stoves and fi replaces

Additional resources for air quality program 

offi cials

http://www.epa.gov/woodstoves

•

•

•

•

•

ultra-clean low-swirl combustion, that can reduce NOx

emissions to less than 9 ppm (at 3 percent oxygen) in 

certain applications (Chen, 2003). This compares to a 

current standard in California of 0.093 lb/MMBtu, which 

is approximately equal to 55 ppm (at 3 percent oxygen). 

To date, this technology has been licensed by Lawrence 

Berkeley National Laboratory for industrial process 

heaters and has been evaluated in a 15-kilowatt spa heater 

(where it reduced NOx emissions from 150 ppm to less 

than 12 ppm). Thus far, the technology has not been used 

in a residential furnace application, although the potential 

does exist to adapt the technology for that application.

Low-Sulfur Diesel Fuel 

Signifi cant potential exists for reducing SO2 emissions 

from residential boilers and furnaces by substituting low- 

(500 ppm) and ultra-low- (15 ppm) sulfur oil for current 

home heating oil, which averages 2,500 ppm sulfur content 

(Bookhart, 2003). 

The New York State Energy Research and Development 

Authority (NYSERDA) and Brookhaven National 

Laboratories recently conducted a three-year 

demonstration project using low-sulfur fuel for residential 

heating. One thousand homes participated in the study, 

which used diesel fuel with a sulfur content of 500 ppm. 

Over the course of the project, use of low-sulfur oil 

caused maintenance and service requirements to decline 

substantially, while at the same time dramatically reducing 

SO2 emissions (EPSA, 2005). 

According to the Empire State Petroleum Association, 

heating oil companies are willing to market low-sulfur 

fuel oil to their customers; however, they have been 

discouraged from doing so because state tax laws treat 

the low-sulfur fuel as a motor vehicle fuel, subjecting it 

to the same taxes that are imposed on highway diesel fuel 

(EPSA, 2005).

Legislators in several states have proposed low-sulfur 

requirements for home heating oil. Rhode Island Senate 

Bill 962 and House Bill 6247 would limit the sulfur 

content of home heating oil to 500 ppm by June 1, 2006. 

However, both bills failed to come up for a formal vote 

(Moura, 2005; Sosnowksi, 2005). In New York State, 

legislation is pending that would direct the Department of 

Environmental Conservation (DEC) to enact regulations 

limiting allowable sulfur levels in home heating fuel (Bill 

No. A6453).

Appliance Effi ciency Standards for Boilers 

and Furnaces

As described above, residential furnaces have been 

subject, under NAECA of 1987, to a minimum Annual 

Fuel Utilization Effi ciency requirement of 78 percent since 

1992. However, furnaces are currently available with 

effi ciency ratings of 90 percent or greater. According to 

the Boston-based Consortium for Energy Effi ciency, Inc., 

22 percent of homes built in 2002 were equipped with 

furnaces that achieved 90 percent Annual Fuel Utilization 

Effi ciency; moreover, as natural gas prices increase, the 

cost-effectiveness of these higher cost units should continue 

to improve (Home Builders Association of Metro Denver, 

2004). DOE is currently developing updated standards for 

residential furnaces and boilers; however, the rulemaking 

has been delayed and is not expected to be completed 

until fall 2007 (ACEEE, 2005). As a result, the American 

Council for an Energy-Effi cient Economy recommends 

that individual states adopt minimum effi ciency standards 

for residential furnaces and boilers. Because federal law 

already covers residential furnaces, states will need to 

apply for a waiver of federal preemption. 

Wood Stove Burn Bans

Local agencies throughout the U.S. have instituted 

restrictions on wood stove use during periods of poor air 

quality. For example, since 1988, the Puget Sound Clean 

Air Agency has instituted temporary restrictions on indoor 

and outdoor wood burning whenever PM levels exceed a 

predetermined level. The bans are instituted in two stages. 

During a fi rst stage ban, residential and commercial 

buildings are prohibited from burning wood in any stove 

or fi replace that is not EPA-certifi ed. During a second 

stage ban, all buildings are prohibited from burning wood 

in either a certifi ed or uncertifi ed wood stove. Buildings 

that do not have an adequate source of heat without 

burning wood are exempted from the bans. In 2005, the 

state legislature adopted a bill revising the thresholds 

for a burn ban (HB 1032: Modifying Burn Ban Triggers, 

2005). Over the past fi ve years, the number of burn bans 

in a given year has ranged from zero to 12 (Puget Sound 

CAA, 2005). Many other localities have instituted similar 
262 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

measures.

Wood Stove Changeout Programs

A growing number of communities have been exploring 

wood stove changeout programs as an option for 

addressing wintertime particulate air pollution. In 2005, 

EPA provided funding and technical support for the 

development of two model programs. A panel convened 

by the National Academies of Sciences (NAS) has 

encouraged the Agency to pursue this type of initiative 

(NAS, 2004). EPA and its project partners initiated one 

such program in June 2005 in Libby, Montana, a small 

town in western Montana. Outside of California, Libby is 

the only area in the West that currently exceeds the PM2.5

standard, and wood combustion contributes more than 80 

percent of the area’s PM2.5 load during the winter season 

(Houck, 2005b). The hearth industry has provided over 

$1 million in wood stoves and other products to assist in 

this campaign (Wood, 2005). The Libby experience is 

expected to be a test case for eastern states considering 

similar programs. 

On September 29, 2005, the Southwest Pennsylvania Air 

Quality Partnership announced the start of its wood stove 

changeout program with a $100,000 grant from EPA and 

others, and an $80,000 grant from the Allegheny County 

Health Department. The program offers free changeouts 

for low-income families and replacements at a discount for 

other residents (Allegheny County, 2005).

EPA’s website, www.epa.gov/woodstoves/changeout.

html, provides additional information on EPA’s wood 

stove changeout program, including technical resources 

for launching a local initiative. Other communities, such 

as Delta County, Colorado, have offered rebates or low 

interest loans for stove changeouts. In the Delta County 

program, the amount of the rebate varied depending on the 

effi ciency and type of the new model. For instance, higher 

rebates were awarded to households that installed pellet or 

gas stoves.

EPA is developing a guidance document on quantifying 

the emissions reductions associated with wood stove 

changeouts for state agencies seeking to use emissions 

reductions from such programs for State Implementation 

Plan (SIP) credit. More information should be available 

from EPA’s website when the guidance is completed.

Finally, EPA includes wood stove changeouts in its list of 

ideas for supplemental environmental projects, or SEPs 

(EPA, 2005b). A SEP is a project that the defendant in an 

enforcement action agrees to perform or fund in partial 

settlement of the case.

Wood Stove Education Campaigns

Between 1999 and 2003, Natural Resources Canada 

led a multi-stakeholder committee in designing and 

implementing a national wood heat education campaign, 

now called Burn it Smart. Burn it Smart aims to reduce 

emissions from residential wood combustion by educating 

consumers on the health and safety aspects of wood 

combustion, proper methods of wood burning, and the 

technologies that are available for reducing emissions. 

State and local agencies seeking to educate the public on 

these topics will benefi t from the educational brochures, 

fact sheets and poster displays developed by the program. 

Also, the program conducts community workshops for the 

general public and industry professionals in an effort to 

reduce emissions. More information is available at www.

burnitsmart.org.

Regulation of Residential Wood Boilers

Over the past year, outdoor residential wood boilers have 

become a focus of heightened concern and state regulatory 

attention because of their high air pollution emissions 

rates and growing popularity. Vermont has proposed 

a rule to regulate new wood boilers, and the New York 

Attorney General has petitioned EPA to promulgate NSPS 

standards for the boilers or revise the existing standards 

for residential wood stoves to include outdoor wood boilers 

(Spitzer, 2005a). EPA is considering its response to this 

petition and has been meeting with boiler manufacturers 

to discuss options for reducing emissions. Several 

manufacturers have indicated that they could signifi cantly 

reduce emissions from new models in less than one year 

(Wood, 2005). Additional states are encouraging EPA’s 

efforts as the Agency weighs its options, and some states 

are pursuing their own regulations. A report by the New 

York Attorney General’s Offi ce provides an example of a 

local ordinance regulating the use of wood boilers (Spitzer, 

2005b). The report also provides background information 

on the cost and performance of wood boiler technology. 

A federal response could avoid a patchwork of state 

regulations, both in terms of the performance standard and 

the test method used to determine emissions performance.

EPA and others are participating in a new ASTM 

committee that is working to develop a consensus test 

method and potentially a consensus emissions standard for 

outdoor wood boilers. This will be a multi-year process 

(Wood, 2005).

Wood Stove Mandatory Removal Programs

Several communities in California and Nevada, including 

the San Joaquin Valley, Mammoth Lakes and Reno, require 

all non-EPA-certifi ed wood stoves to be removed or retired 

prior to the sale or transfer of a property. This strategy 

can be a powerful method for accelerating the removal of 

older stoves and is generally feasible because the cost of 

removing a stove usually constitutes an insignifi cant share 
 Chapter 18 - Residential Fuel Combustion and Electricity Use 263

of the property sale price. 

Outdoor Burning Restrictions

The primary strategy for addressing emissions from open 

burning is to ban the practice, while providing waste 

disposal alternatives. Public education and consistent 

enforcement are also key to program success. Increasing 

household waste pickups, establishing and promoting free 

or low-cost drop-off centers, and educating residents about 

disposal alternatives will all serve to discourage open 

burning (EPA, 2001b; EPA, 2003). 

Connecticut, Maine, Massachusetts, New Jersey, New 

Hampshire and Vermont have statewide bans on backyard 

burning of household waste. New York distributes 

brochures on the hazards of backyard burning. Forsyth 

County strictly enforces North Carolina’s statewide ban 

against burning garbage by penalizing fi rst-time offenders 

with fi nes ranging from $100 to $10,000 (EPA, 2003).

In response to high rates of residential garbage burning in 

northeastern Minnesota and northwestern Wisconsin, the 

Western Lake Superior Sanitary District has developed 

a toolkit of information for local offi cials to assist them 

in addressing the problem. The toolkit includes a model 

ordinance to regulate outdoor burning, public education 

materials to alert people to the hazards of burning 

household waste, case studies of successful programs, 

as well as other resources. The toolkit is available at 

www.wlssd.com/Open_Burning/Clearing_the_Air_

downloadvs.pdf.

Building Envelope and Appliance Effi ciency 

Incentives

The Energy Policy Act of 2005 provides more than $2 

billion in tax incentives for advanced energy-saving 

technologies and practices. Most of these incentives are 

available in the period 2006–2007 (Nadel, 2005). State 

policymakers should familiarize themselves with the 

various provisions of the bill and consider complementary 

programs to take maximum advantage of the opportunities 

available. For example, the legislation provides a $2,000 

tax credit for new homes that use 50 percent less energy for 

space heating and cooling relative to homes built pursuant 

to the 2003 International Energy Conservation Code. The 

bill also provides tax credits for high-effi ciency appliances 

such as central air conditioners, heat pumps, furnaces and 

water heaters. State and local energy programs can help in 

promoting awareness of the tax credits and other provisions 

of the bill. A complete discussion of these opportunities 

is available in a report prepared by the American Council 

for an Energy-Effi cient Economy and entitled The Federal 

Energy Policy Act of 2005 and its Implications for Energy 

Effi ciency Program Efforts (Nadel, 2005).

Other Measures

On December 15, 2005, the San Joaquin Valley UAPCD 

adopted a rule (Rule 9510) requiring developers of larger 

residential, commercial and industrial projects to adopt 

measures to reduce NOx and PM emissions from projected 

baseline levels. The rule requires developers to reduce 

NOx emissions by 33 percent and particulate emissions by 

50 percent of a project’s baseline. If projected emissions 

are forecast to exceed the minimum baseline reductions, 

the developer can offset the difference by paying a fee 

to the Air District, which is then used to fund clean air 

projects. Developers have several options for offsetting 

their baseline emissions, including: (1) not installing 

wood stoves, (2) increasing energy effi ciency, (3) locating 

homes close to retail outlets or (4) creating higher density 

developments (San Joaquin Valley UAPCD, 2005b).

References

Allegheny County. SWPA Air Quality Partnership, Inc. 

Announces Great American Woodstove Changeout 

Program, September 29, 2005. www.county.allegheny.

pa.us/news/250929.asp.

American Council for an Energy-Effi cient Economy 

(ACEEE). Consumer Guide to Home Energy Savings,

accessed December 1, 2005, from: www.aceee.org/

consumerguide/index.htm.

Batey, J., and R. McDonald. Advantages of Low Sulfur 

Home Heating Oil: Interim Report of Compiled Research, 

Studies, and Data Resources, prepared with the National 

Oilheat Research Alliance and the U.S. Department of 

Energy, December 2002.

Boookhart, D. and K. Zien, Consumer Energy Council of 

America. Low Sulfur Heating Oil: Evaluating the Impacts 

on Consumers. September 2003.

Brockman, L., U.S. Environmental Protection Agency. 

EPA’s Offi ce of Air Quality Planning and Standards 

Efforts Being Considered for EPA Residential Wood Smoke 

Emissions Reduction Initiative, November 2004.

Brockman, L., U.S. Environmental Protection Agency. 

Woodstove Changeout Workshop: Nature and Magnitude 

of the Problem, February 24, 2005. (2005a)

Brockman, L., U.S. Environmental Protection Agency. 

Personal communication with M.J. Bradley & Associates, 

October 11, 2005. (2005b)

Center for Clean Air Policy (CCAP). Draft Report: 

Reducing Emissions from Residential Oil Furnaces 

and Boilers: Report to EPA’s State and Local Capacity 
264 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Building Branch, December 12, 2005.

Chen, A. Low-Swirl Combustion Clears the Air, July 28, 

2003. www.lbl.gov/Science-Articles/Archive/EETD-lowswirl-combustion.html.

E Source. Technology Atlas Series. 1997.

Edison Electric Institute. Energy Policy Act of 2005: 

Summary Title I—Energy Effi ciency, August 2005.

Environment Canada, Ministère de l’Environnement du 

Québec, Ville de Montréal. Residential Wood Heating: 

Summary of Results from 1999 to 2002, 2004.

Empire State Petroleum Association (EPSA). 2005 

Legislative and Regulatory Agenda, accessed December 

15, 2005, from: www.espa.net/legisnews.htm.

Home Builders Association of Metro Denver, Built 

Green. Biting the 90 AFUE Bullet, April 10, 2004. www.

builtgreen.org/articles/0307_AFUE_bullet.htm.

Houck, J., and P.E. Tiegs. Residential Wood Combustion 

Technology Review: Volume 1 Technical Report (EPA-600/

R-98-174a), December 1998. www.epa.gov/ttn/chief/ap42/

ch01/related/woodstove.pdf.

Houck, J., A.T. Scott, J.T. Sorenson, and B.S. Davis. “Air 

Emissions Comparisons Between Cordwood and WaxSawdust Firelogs Burned in Residential Fireplaces,” 

Bioenergy 2000: Moving Technology into the Marketplace, 

October 2000. www.nrbp.org/papers/036.pdf.

Houck, James E. and D.R. Broderick. PM2.5 Emission 

Reduction Benefi ts of Replacing Conventional Uncertifi ed 

Cordwood Stoves with Certifi ed Cordwood Stoves or 

Modern Pellet Stoves, May 26, 2005. (2005a)

Houck, James E., D.R. Broderick and C. Keithley. “All 

Eyes on Libby,” Hearth and Home, February 2005. 

(2005b)

Karney, Richard H., ENERGY STAR Program, U.S. 

Department of Energy. Memorandum Regarding Water 

Heaters, January 6, 2004. www.energystar.gov/ia/

partners/prod_development/new_specs/downloads/water_

heaters/DOE_waterheaterletter_fi nal_1.6.04.pdf.

McDonald, R.J., and J. Batey. “Benefi ts and Advantages of 

Marketing Low Sulfur Heating Oil Including Results from 

a New York State Low Sulfur Market Demonstration,” 

2003 National Oilheat Research Alliance Technology 

Symposium, June 9, 2003. www.oilheating.com/

downloads/Brookhaven_low_sulfur.doc.

Moura, Paul E., and B.J. Long, Rhode Island House of 

Representatives. An Act Relating to Air Pollution—Home 

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billtext05/housetext05/h6247.pdf.

Nadel, Steven, American Council for an Energy-Effi cient 

Economy. The Federal Energy Policy Act of 2005 and 

its Implications for Energy Effi ciency Program Efforts,

September 2005.

Nadel, Steven, A. deLaski, J. Kleisch, and T. Kubo. 

Leading the Way: Continued Opportunities for New State 

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Number ASAP-5/ACEEE-A051), January 2005.

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Committee on Air Quality Management in the United 

States. Air Quality Management in the United States,

2004.

National Oilheat Research Alliance (NORA). Advantages 

of Low Sulfur Home Heating Oil—Why You Should 

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LOW_SULFUR_V5.pdf.

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15, 2005, from: www.tide.com/tidecoldwater.

Puget Sound Clean Air Agency (CAA). What Is a Burn 

Ban? 2005. www.pscleanair.org/burning/whatisaburnban.

shtml.

Russell, Gerard F. “Twilight for Wood Stoves?” Worcester 

Telegram & Gazette, December 27, 2005.

San Joaquin Valley Unifi ed Air Pollution Control District 

(UAPCD). Final Draft Staff Report: Rule 4905 (Natural 

Gas-Fired, Fan-Type Residential Central Furnaces), 

September 15, 2005a.

San Joaquin Valley Unifi ed Air Pollution Control District 

(UAPCD). “New Developments To Reduce Air-Pollution 

Emissions,” San Joaquin Valley UAPCD News Release, 

December 15, 2005b.

Schauer, J.J., and G.R. Cass. “Source Apportionment of 

Wintertime Gas-Phase and Particle-Phase Air Pollutants 

Using Organic Compounds as Tracers,” Environmental 

Science & Technology 34: 1821, 2000.

Spitzer, Eliot, Attorney General, State of New York. Letter 

to Stephen L. Johnson, Administrator, U.S. Environmental 

Protection Agency, Re: Petition for Rulemaking under 

42 U.S.C. §7411(b)(1) Regarding Outdoor Wood Boilers,

August 11, 2005. www.oag.state.ny.us/press/2005/aug/
 Chapter 18 - Residential Fuel Combustion and Electricity Use 265

Petition.pdf. (2005a)

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Gets in Your Lungs: Outdoor Wood Boilers in New York 

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September 15, 2005.
266 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Commercial cooking establishments—including restaurants, industrial-scale food processing facilities and street 

vendors—are responsible for preparing a growing share of 

the food consumed in the U.S. One indicator of this trend 

is the increase in meals consumed outside the home. In 

1970, Americans devoted 34 percent of their total food 

budget to meals consumed away from home. Today, 

these expenses account for more than 40 percent of total 

U.S. food expenditures (Dumagan, 1995; USDA, 2005). 

Demand for ready-made meals prepared in the home has 

also increased in response to economic and cultural trends 

(Woon, 2005).

Commercial cooking operations produce a mixture of 

solid, liquid and gaseous particles, including water and 

grease, non-condensable gases and solid organic matter. 

Some portion of the water and grease vapor condenses on 

the ventilation equipment, while remaining particles and 

grease droplets are released to the atmosphere. How much 

of the vapor is condensed rather than released depends on 

a host of factors.

According to EPA, the majority of PM emissions from 

the commercial cooking sector come from the cooking 

of meat products (Roe, 2004). In particular, charbroiling 

generates over 80 percent of total PM2.5 emissions from the 

commercial cooking sector (Roe, 2004).

Commercial cooking operations use two types of 

charbroilers: underfi red and chain-driven. The vast 

majority of emissions come from the use of underfi red 

charbroilers, although regulatory efforts have focused on 

the control of chain-driven charbroilers used by fast-food 

restaurants (Perryman, 1997).

Emissions rates from commercial cooking vary by type 

of appliance, type of meat, the fat content of the meat 

and cooking conditions (McDonald, 2003). High-fat 

meats cooked on an underfi red charbroiler produce the 

highest fi ne particulate (PM2.5) emissions. PM emissions 

from meat cooking are primarily in the PM2.5 size range 

(McDonald, 2003).

Chapter 19

Commercial Cooking
 Chapter 19 - Commercial Cooking 267

This chapter discusses the technology and policy options 

available for reducing PM2.5 emissions from commercial 

cooking establishments.

Sector Profi le

There are over 900,000 restaurants in the U.S. and 

they employ more than 12 million people, making the 

commercial cooking sector the nation’s second largest 

employer. (Only the government sector employs more 

people in the U.S.) Industry sales in 2004 were $476 

billion, an 11-fold increase from 1970 sales of $43 billion 

(National Restaurant Association, 2005).

Commercial cooking establishments are spread throughout 

the U.S. and are expected to continue growing in number 

as the population increases. Between 2000 and 2020, the 

U.S. population is expected to grow by between 50 and 80 

million people. In part because of the larger population 

and in part because of greater affl uence, total U.S. food 

expenditures are projected to rise a further 26 percent 

between 2000 and 2020, from $800 billion in 2000 to 

over $1 trillion in 2020 (Blisard, 2002). While not all 

of this food will be prepared at commercial cooking 

facilities, the amount of food purchased outside the home 

is also expected to increase. For example, the proportion 

of meat consumed outside the home is expected to rise 

between 2000 and 2020, as shown in Table 19.1. (As 

mentioned above, the cooking of meat is the largest source 

of emissions from commercial cooking operations.) As 

more Americans go out for meals, emissions from the 

commercial cooking sector may well become a more 

substantial air pollution problem.

EPA’s National Emissions Inventory divides the 

commercial cooking sector into fi ve categories: chaindriven (or conveyorized) charbroilers, underfi red 

charbroilers, deep fat fryers, fl at griddle fryers, and 

clamshell griddle fryers. 

Chain-driven Broilers. Chain-driven charbroilers, 

commonly used at fast food restaurants, use a conveyer 

belt to carry the food product through the heat source, 

often cooking both sides of the food in a single pass. 

Most chain-driven charbroilers are fueled by natural gas, 

although electric models are also available (Perryman, 

1997).

Underfi red Charbroilers. Underfi red charbroilers 

resemble a barbecue and have a heat source below a 

heavy metal grid, which marks the food with a distinctive 

striping. Some restaurants make their charbroiler, which 

generates fl ames and smoke, a showpiece within their 

establishment (Fisher, 2002). Examples include broilers, 

grill charbroilers, fl ame broilers and direct-fi red barbecues. 

Charbroilers generate particulate emissions when grease 

falls from the meat onto the radiant surface. Unburned 

drippings collect in a grease tray. Most charbroilers burn 

natural gas, but some use charcoal or wood with ceramic 

stones to distribute the heat (Perryman, 1997). Because 

of the smoke they generate, charbroilers require signifi cant 

ventilation (Fisher, 2002).

Deep Fat Fryers. Deep fat fryers use an exposed hot 

metal surface to heat cooking oil, which is then used to 

cook the food. Most raw food products contain a high 

percentage of water by weight (10–75 percent), and most 

of the water at the surface vaporizes during the cooking 

process, creating an oily mist (Perryman, 1997). Fastfood establishments use deep fat fryers to prepare food in 

batches. 

Griddles and Griddle Hybrids. Flat griddles are 

appliances that consist of an exposed metal plate used to 

fry food. Most griddles are gas-fi red, although some are 

electric. The Clamshell® griddle is a newer type of griddle 

that employs a two-sided cooking confi guration to reduce 

cooking time, thereby also reducing emissions (Perryman, 

1997).

Table 19.1

Proportion of meat consumed outside the home, 2000–2020

Type of Meat Commodity Market Share (%) 2000 Commodity Market Share (%) 2020

At home Outside At home Outside

Beef 67 33 65 35

Pork 79 21 77 23

Poultry 68 32 69 31

Fish 66 34 64 36

Other meat 77 23 76 24

Source: Blisard, 2002
268 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Sector Emissions

A revised inventory methodology developed by EPA and 

Pechan Associates in 2004 estimates that commercial 

cooking establishments generate nearly 80,000 tons of 

PM2.5 emissions per year (Roe, 2004).1

 (The updated 

methodology resulted in a fi ve-fold increase in estimated 

PM2.5 emissions from the sector relative to the 1999 

inventory.) 

To put this estimate in perspective, 80,000 tons is 

equivalent to 6 percent of the total direct PM2.5 emissions 

that EPA estimates were generated by all point source 

categories in 1999 (e.g., power plants and industrial 

facilities). (This is 1.4 percent of the 1999 total direct 

PM2.5 area source emissions inventory.)

1. EPA’s revised estimate does not include all cooking processes. For 

example, it does not include residential or special-event cooking, or 

cooking processes at institutional facilities. The estimate also does not 

include criteria pollutant emissions associated with fuel combustion 

by cooking equipment. Emissions from fuel combustion are instead 

included in the commercial fuel combustion emissions sector of the 

National Emissions Inventory (Roe, 2004).

Table 19.2 reports estimated PM2.5 emissions from the 

commercial cooking sector (meat and potatoes only) by 

equipment type. Underfi red charbroilers produced 74 

percent of PM2.5 emissions, fl at griddle frying produced 

15 percent, and chain-driven charbroilers produced 10 

percent. Particulate emissions from deep fat fryers are 

below detectable levels (Whynot, 1999). 

Particle emissions from meat cooking are primarily in 

the PM2.5 size range (McDonald, 2003). For example, 

according to EPA’s revised inventory data, 97 percent of 

the PM10 emissions attributable to underfi red charbroiling 

are in the fi ne particle size range (see Table 19.2). 

Sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions 

from the commercial cooking sector are generally not 

addressed in the literature. Studies of commercial cooking 

focus on PM, volatile organic compounds (VOCs), and 

their specifi c components. NOx and SO2 emissions are 

attributable primarily to the energy use associated with 

commercial cooking equipment, as opposed to the actual 

cooking process. The emissions associated with electricity 

use are addressed in Chapter 7, Electric Generating Units.

Table 19.2

National Commercial Cooking Sector Emissions, 2002

Equipment Type PM10 PM2.5

Tons/year Percent of sector 

emissions

Tons/year Percent of sector 

emissions

Underfi red charbroiling 60,304 71% 58,295 74%

Chain-driven charbroiling 8,460 10% 8,201 10%

Deep fat frying ND ND ND ND

Flat griddle frying 15,679 18% 11,916 15%

Clamshell griddle frying 1,073 1% 909 1%

Total 85,515 100% 79,321 100%

ND = no data

Source: Roe, 2004

Table 19.3

PM2.5 Emissions Rates from Cooking Meat (lb per unit of meat)

Meat Fat Content Appliance PM2.5/1000 lb

Hamburger 21% Chaindriven charbroiler 4.5–7.4

25% Underfi red Charbroiler 15.0–40.0

21% Underfi red Charbroiler 7.1

Steak 3% Underfi red Charbroiler 7.8

Chicken with skin 10-30% Underfi red Charbroiler 7.2–10.4

Source: McDonald, 2003
 Chapter 19 - Commercial Cooking 269

The PM2.5 emissions rates for charbroiling hamburger, 

steak and chicken range from 4.5 to 40.0 pounds (lb) per 

1,000 lb of uncooked meat. High-fat hamburgers (25 

percent fat) cooked with an underfi red charbroiler produce 

the highest amount of PM2.5 (McDonald, 2003). Table 19.3 

summarizes the PM2.5 emissions rates of several meat/

appliance combinations.

Emissions Control Opportunities

Most PM2.5 emissions from commercial cooking 

establishments are generated when grease from the meat 

falls into the heating element or fl ame and combusts. 

Controlling emissions from the largest sources of 

emissions, underfi red charbroilers, can be very expensive 

because of the relatively low emissions generated by any 

single restaurant and the lack of low-cost control options. 

Emissions from chain-driven charbroilers are more costeffective to control and are being regulated in southern 

California by the South Coast Air Quality Management 

District (AQMD).

Chain-Driven Charbroilers

Chain-driven charbroilers generate PM emissions 

when grease from the cooking meat falls onto the 

high temperature radiant surface. The most common 

technology used to control these emissions is the catalytic 

oxidizer (Perryman, 1997).

A fl ameless catalytic oxidizer contains a bed of inert 

ceramic material coated with a metal catalyst that oxidizes 

smoke and gases from the cooking process, converting 

them to carbon dioxide and water. The system is 

mounted into the charbroiler ventilation duct. Engelhard 

manufactures a food-service catalytic oxidizer (Engelhard, 

2004).

In experiments using a catalytic oxidizer, controlled 

emissions from chain-driven charbroilers averaged 1.29 

lb of PM emissions per 1,000 lb of hamburger, an 83 

percent reduction from high-end estimates of uncontrolled 

emissions (Whynot, 1999). Catalytic oxidizers also reduce 

VOC emissions. 

A catalytic oxidizer adds an estimated $3,700 to the 

price of a new conveyorized charbroiler (Sacramento 

Metropolitan AQMD, 2005). For one restaurant in 

California, the installation of a catalyst also cut duct 

cleaning from about four to about two times per year, 

saving approximately $320 per year. In addition—because 

the catalyst refl ects heat back into the charbroiler—natural 

gas use at the restaurant was reduced by about 7 percent 

(Ventura County APCD, 2004a).

A large number of restaurants in southern California have 

installed catalytic oxidizers. The cost-effectiveness of 

installing catalytic oxidizers on commercial charbroilers is 

estimated by South Coast AQMD staff at $1,680–$2,800 

per ton of PM and VOCs reduced. Restaurant operators, 

commenting on South Coast AQMD’s draft rule, have 

reported costs of more than $7,000 per ton of emissions 

reduced (Perryman, 1997). However, according to the 

South Coast AQMD, this higher cost estimate represented 

a unique outlier situation where more extensive structural 

changes to the cooking facility were required (South Coast 

AQMD, 1997b).

Underfi red Charbroilers

Underfi red charbroilers produce four times the emissions 

generated by chain-driven charbroilers per unit of 

product cooked, and are estimated to generate 74 percent 

of the sector’s PM2.5 emissions (Whynot, 1999; Roe, 

2004). However, controlling emissions from underfi red 

charbroilers can be very expensive per ton of PM reduced. 

According to the South Coast AQMD, catalytic oxidizers 

are not effective with underfi red charbroilers because 

the exhaust temperatures are not suffi cient to promote an 

effi cient reaction (Perryman, 1997).

The South Coast AQMD, which has evaluated options for 

controlling PM10 emissions from underfi red charbroilers 

since 1991, concluded in December 2004 that cost-effective 

control options are not available. In the South Coast 

AQMD, underfi red charbroilers contribute 83 percent of 

the restaurant sector PM10 inventory (South Coast AQMD, 

2004).

The South Coast AQMD has focused on two control 

options: (1) the replacement of underfi red charbroilers 

with SmoklessTM broilers, and (2) an add-on scrubber 

manufactured by CAST, Inc. (South Coast AQMD, 2004). 

In 1999, about 70 restaurants in the U.S. used the 

SmoklessTM broiler. This broiler is not a control device, 

but a complete alternative to the traditional underfi red 

charbroiler. Unlike the underfi red broiler, the SmoklessTM

broiler is not a direct-fl ame cooker and may result in 

a product that differs in appearance and taste. This 

contributed to the decision by South Coast AQMD staff to 

recommend against a rule that would require underfi red 

charbroilers to be replaced with this technology or with 

some other alternative cooking device. The SmoklessTM

broiler’s capital cost is approximately $5,550, compared to 

about $3,100 for a similarly sized underfi red charbroiler. 

Replacing an underfi red charbroiler with a SmoklessTM

broiler is reported to reduce PM10 emissions at a cost of 

$3,550 per ton (South Coast AQMD, 2000).

A second emissions control option for underfi red 

charbroilers is the CAST, Inc. add-on scrubber. For a 

very large restaurant (cooking 2,800 lb of meat per week), 

the South Coast AQMD estimates a cost-effectiveness of 
270 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

$1,100–$7,300 per ton of PM10 reduced, depending on the 

type of meat cooked and the volume of make-up air saved 

by the device (South Coast AQMD, 2004).2 According to 

the manufacturer, there are roughly 12 CAST scrubbers 

installed throughout the U.S. and the system has been 

improved over the past several years to increase energy 

savings associated with heating, ventilation and air 

conditioning (Hopkins, 2005).

An electrostatic precipitator (ESP) can also be used to 

control PM emissions. The ESP used for controlling 

charbroiler particulate emissions (called the “Penney-type” 

ESP) involves a two-stage process. The exhaust stream 

enters the fi rst stage from the hood, where it is charged; 

the charged particles are then collected in the second stage. 

The South Coast AQMD warns that improper cleaning can 

interfere with particulate removal effi ciencies (Perryman, 

1997). There are a few dozen ESPs operating at restaurants 

located in the South Coast AQMD area (Whynot, 1999). 

The South Coast AQMD estimates a cost-effectiveness 

of $10,000 per ton of PM reduced for an ESP (Perryman, 

1997).

United Air Specialists, Inc. manufactures an ESP system, 

known as the Smog-Hog® Air Pollution Control System, 

that is designed specifi cally for kitchen emissions control. 

The system is used by hotels, high-rise buildings, airports, 

casinos, food courts and sports and entertainment 

complexes throughout the U.S., including McDonald’s, 

Pizza Hut, Burger King (San Francisco Airport), Planet 

Hollywood, Four Seasons Hotel Boston and Mohegan Sun 

Casino (United Air Specialists, undated).

Additionally, wet scrubbers are capable of PM removal 

effi ciencies of 90 percent or higher, depending on particle 

size, load, fl ow rate and design pressure drop. Wet 

scrubbers rely on a fi nely atomized stream of liquid to 

capture particulate and gaseous pollutants from an exhaust 

stream, like that of a restaurant charbroiler. There are 

several wet scrubbers currently permitted in restaurants in 

the South Coast AQMD area (Perryman, 1997). The South 

Coast AQMD estimates a cost-effectiveness of $13,000 per 

ton of PM reduced for a wet scrubber (Perryman, 1997).

2. Make-up air refers to unconditioned air brought in from the outdoors.

Apart from these add-on controls, the design of a 

charbroiler’s metal grid can infl uence the amount of smoke 

generated by the device. Some grids are designed with a 

series of gutters that channel grease away from the fl ames 

of the broiler and toward the grease pan (Fisher, 2002). 

Some models have a slanted grid that also serves to divert 

grease away from the fl ames. No estimates are currently 

available regarding the effectiveness of these designs in 

reducing PM2.5 emissions. Also, griddles—which do not 

have an exposed fl ame—are available that can create the 

characteristic stripes of an underfi red charbroiler with far 

less smoke and more effi cient energy use (Fisher, 2002).

Flat Griddle and Clamshell® Frying

Regulators have not focused on particulate emissions from 

fl at griddle frying. As shown in Table 19.2, fl at griddle 

fryers account for 15 percent of PM2.5 emissions.

The Clamshell® broiler features an infrared broiler-hood 

mounted over a griddle. This two-sided cooking surface 

reduces cooking time, thereby decreasing emissions 

(Fisher, 2002).

Energy Conservation Measures

Charbroilers can be large consumers of energy, as they 

generally idle at a rate close to their full heat input to be 

ready for the next round of cooking. Testing in Pacifi c Gas 

and Electric Company’s test kitchen revealed that a gas 

underfi red broiler has a cooking effi ciency of only 5 percent 

when cooking 100 lb of food over an eight hour period. 

The heat generated by a charbroiler can also contribute 

to cooling loads in a kitchen, further contributing to a 

restaurant’s energy needs. Although control systems have 

been evaluated that would automatically reduce gas fl ow 

when a charbroiler is on but not cooking, this technology 

is not yet commercially available (Fisher, 2002). Further 

investigation may be warranted in this area in light of the 

potential energy savings.

Regulatory Authority

There are no federal regulatory requirements for 

controlling PM2.5 emissions from restaurants, and state 

and local air agencies have generally not been active in 

regulating commercial cooking facilities. The South Coast 

AQMD regulates chain-driven charbroilers, as discussed 

below. The South Coast AQMD also lists catalytic 

oxidizers in its best available control technology (BACT) 

guidelines for controlling PM10 emissions from chaindriven charbroilers (Perryman, 1997).

Local public health departments may regulate opacity 

(visible smoke) and odors from commercial cooking 

establishments in residential or commercial areas. The 

strategies used to comply with these regulations may also 

United Air Specialists, Inc. Smog-Hog®

Courtesy of United Air Specialists, Inc.
 Chapter 19 - Commercial Cooking 271

reduce PM2.5 emissions (e.g., installation of a catalytic 

oxidizer).

State and Local Policy Measures

South Coast AQMD Rule 1138 regulates chain-driven 

charbroilers (Roe, 2004). It requires operators of both new 

and existing chain-driven charbroilers to install a catalytic 

oxidizer. Alternative control devices can be used if they 

are at least as effective as a catalytic oxidizer in reducing 

PM and VOC emissions. Chain-driven charbroilers 

cooking less than 875 lb of meat per week are exempt 

(South Coast AQMD, 1997a). 

Other areas have adopted or have considered adopting 

the South Coast AQMD rule. The Ventura County Air 

Pollution Control District and the San Joaquin Valley 

Unifi ed Air Pollution District, both in California, have 

adopted the South Coast AQMD rule (Ventura County 

APCD, 2004b; San Joaquin Valley UAPD, 2002). New 

Jersey is considering adopting the South Coast AQMD 

standards for chain-driven charbroilers, and also 

recommends investigating the use of the Smog-Hog® ESP 

and catalytic controls on some operations (New Jersey 

Homes and Restaurants Workgroup, 2005).

The South Coast AQMD conducted extensive research 

on emissions controls for underfi red charbroilers and 

concluded that none of the options now available met its 

cost-effectiveness criteria; accordingly, the agency chose 

not to regulate these charbroilers. Staff have recommended 

that the Board of Governors look to other industry sectors 

for more cost-effective particulate reductions (South Coast 

AQMD, 2004). 

In nonattainment areas around Aspen, Colorado, Chapter 

6.12 of the Pitkin County Code requires commercial 

cooking operations to maintain a control device on 

charbroilers installed on or after January 1, 1993. The 

control device must reduce uncontrolled PM10 emissions 

by at least 90 percent (Pitkin County Code, 2004). The 

Pitkin County Code also prohibits the cooking of high 

fat-content meat (greater than 15 percent precooked fat 

content by weight) on charbroilers installed after April 

25, 1983 but before January 1, 1993, unless an emissions 

control device has been installed that reduces uncontrolled 

PM10 emissions by at least 90 percent (Pitkin County 

Code, 2004). Finally, any commercial cooking facility 

within specifi ed zones in Pitkin County that proposes 

to extensively remodel its kitchen is required to install a 

grooved griddle or an equivalent low-emissions cooking 

device if high fat-content meats are regular menu items. 

Pitkin County required such controls to be installed on 

existing restaurants by December 1, 1984 (Pitkin County 

Code, 2004).

The State of Colorado has published a “Guide to 

Environmental Regulations for Restaurants and Food 

Service Businesses.” This document instructs facilities to 

check for smoke from outside hood stacks and to use good 

cooking practices; it also suggests that restaurants with 

chain-driven charbroilers consider installing a catalytic 

converter and that other restaurants with underfi red 

charbroilers consider using a scrubber or ESP (Colorado 

Department of Public Health and the Environment, 1999).

References

Blisard, Noel, B. Lin, J. Cromartie, and N. Ballenger, 

U.S. Department of Agriculture. “America’s Changing 

Appetite: Food Consumption and Spending to 2020,” 

Food Review 25(1): 2-9, May 2002. www.ers.usda.gov/

publications/FoodReview/May2002/frvol25i1a.pdf.

California Energy Commission. Commercial Kitchen 

Ventilation and Emissions (P600-00-029), December 1999. 

www.energy.ca.gov/reports/2002-01-10_600-00-029.pdf.

Colorado Department of Public Health and Environment. 

A Guide to Environmental Regulations for Restaurants & 

Food Service Businesses, December 1999. www.cdphe.

state.co.us/ap/down/restguideweb.pdf.

Dumagan, J.C., and J.W. Hackett. “Almost Half of the Food 

Budget Is Spent Eating out,” Food Review, Jan-April 1995. 

Engelhard Corporation. Restaurant Chains Clear the Air 

with Engelhard Technology, November 24, 2004. www.

engelhard.com.

Fisher, D., Food Service Technology Center. Commercial 

Cooking Appliance Technology Assessment, 2002. www.

fi shnick.com/publications/techassessment.

Hopkins, D. Personal communication with M.J. Bradley 

& Associates, December 13, 2005. www.airscrubbers.

com/home.php.

McDonald, J.D., B. Zielinska, E.M. Fujita, J.C. Sagebiel, 

J.C. Chow, and J.G. Watson. “Emissions from Charbroiling 

and Grilling of Chicken and Beef,” Journal of Air & Waste 

Management Association 53: 185-194, February 2003.

National Restaurant Association. Restaurant Industry 

2005 Fact Sheet, 2005. www.restaurant.org/pdfs/research/

2005factsheet.pdf.

New Jersey Homes and Restaurants Workgroup. A 

Collaborative Report Presenting Recommended Air 

Quality Strategies for Further Consideration by the State 

of New Jersey, October 31, 2005. www.state.nj.us/dep/

airworkgroups/docs/fi nal_hr_workgroup_report.pdf.
272 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Perryman, P., and P. Votlucka, South Coast Air Quality 

Management District. Staff Report for Proposed Rule 

1138: Control of Emissions from Restaurant Operations,

October 1997.

Pitkin County Code. Title 6: Health and Safety, July 23, 

2004. www.aspenpitkin.com/pdfs/depts/71/Pitkinco06tx.

pdf.

Roe, S., M. Spivey, H. Lindquist, P. Hemmer, E. H. Pechan 

& Associates, Inc., and R. Huntley, U.S. Environmental 

Protection Agency, Emission Factor and Inventory Group. 

National Emissions Inventory for Commercial Cooking, 

June 2004. www.epa.gov/ttn/chief/conference/ei13/

pointarea/roe.pdf.

Sacramento Metropolitan Air Quality Management 

District (AQMD). Final Staff Report SB656: 

Assessment and Control Measure Evaluation,

July 28, 2005. www.airquality.org/notices/SB656/

HearingStaffReport20050728.pdf.

San Joaquin Valley Unifi ed Air Pollution District (UAPD). 

Rule 4692—Commercial Charbroiling, March 21, 2002. 

www.arb.ca.gov/DRDB/SJU/CURHTML/R4692.pdf.

South Coast Air Quality Management District (AQMD). 

Rule 1138—Control of Emissions from Restaurant 

Operations, November 14, 1997. www.arb.ca.gov/DRDB/

SC/CURHTML/R1138.htm. (1997a)

South Coast Air Quality Management District (AQMD). 

Board Meeting, Agenda No. 32: Proposal for Public 

Hearing To Adopt Proposed Rule 1138—Control of 

Emissions from Restaurant Operations, November 14, 

1997. www.aqmd.gov/hb/1997/971132a.html. (1997b)

South Coast Air Quality Management District (AQMD). 

Board Meeting: Status Report on Controlling Particulate 

Matter and Volatile Organic Compound Emissions from 

Restaurant Operations, August 18, 2000. www.aqmd.gov/

hb/2000/000820a.html.

South Coast Air Quality Management District (AQMD) 

Board Meeting: Staff Recommendations regarding 

Controlling Emissions from Restaurant Operations, 

December 3, 2004. www.aqmd.gov/hb/2004/041239a.

html.

United Air Specialists. Kitchen Emissions Systems - 

SMOG-HOG User List, undated.

U.S. Environmental Protection Agency (EPA). “Emissions 

from Street Vendor Cooking Devices (Charcoal Grilling)” 

(EPA 600/SR 99 048), June 1999.

U.S. Department of Agriculture (USDA), Economic 

Research Service. Food Consumption: Household Food 

Expenditures, accessed December 2, 2005, from: www.

ers.usda.gov/briefi ng/consumption/Expenditures.htm.

Ventura County Air Pollution Control District (APCD). 

Restaurant Cooking Operations: Final Staff Report, 

August 31, 2004. www.vcapcd.org/pubs/Rules/Rule7425/

R7425_SR0831.pdf. (2004a)

Ventura County Air Pollution Control District (APCD). 

Rule 74.25:Restaurant Cooking Operations, October 12, 

2004. www.arb.ca.gov/DRDB/VEN/CURHTML/R74-

25.PDF. (2004b)

Welch, W., South Coast Air Quality Management District. 

Effi cient and Cost-Effective Control Technologies for 

Underfi red Charbroilers: Development and Demonstration 

of Emission Control Technologies for Commercial 

Underfi red Charbroilers, Final Report, February 12, 1999.

Whynot, J., G. Quinn, P. Perryman, and P. Votlucka. 

“Control of Fine Particulate (PM2.5) Emissions from 

Restaurant Operations.” Journal of Air & Waste 

Management Association 49: PM-95-99, 1999. www.

awma.org/journal/special/Sept99/contents.asp.

Woon, E. Increased Sophistication within US Ready 

Meals Sector, accessed August 25, 2005, from: www.justfood.com/features_detail.asp?art=1004.
274 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Introduction

Fugitive dust refers to particles, most commonly derived 

from soil, that are lifted and suspended in the ambient air 

by human activities and natural forces, such as agricultural 

tilling, motor vehicle use and wind. Fugitive dust does 

not include particulate matter (PM) emitted directly from 

stationary or mobile sources (EPA, 2005a).

The major sources of fugitive dust are paved and unpaved 

roads, agricultural operations, construction projects and 

wind erosion from both agricultural and non-agricultural 

lands (Pace, 2005). Fugitive dust is comprised primarily 

of coarse PM (between 10 and 2.5 micrometers (μm) in 

diameter). PM2.5 (particles 2.5 μm or less in diameter) 

is a smaller share of the mix. For example, a study that 

measured the PM emissions from the unpaved roads of 

two sand and gravel plants in California found that PM2.5

contributed 15 percent of total PM10 emissions (Hayden, 

2005). A separate study by EPA that reviewed several 

studies suggests that PM2.5 accounts, on average, for 10 

percent of fugitive dust PM10 emissions (Pace, 2005).

According to EPA’s 1999 National Emissions Inventory, 

fugitive dust is a major component of the direct PM2.5

inventory, contributing roughly 50 percent of total direct 

emissions. EPA estimates that vehicle travel on unpaved 

roads was responsible for 1.3 million tons of PM2.5

emissions in 1999. This is approximately equal to the total 

direct PM2.5 emissions that EPA estimates all point source 

categories (e.g., power plants and industrial facilities) 

generated in 1999. EPA estimates that vehicle travel on 

paved roads produced roughly 700,000 tons of PM2.5 in 

1999, or roughly half the quantity generated from unpaved 

roads. Agricultural sources (crops and livestock) are also 

reported to be a major source of fugitive dust, generating 

just under one million tons of PM2.5 in 1999. See Table 

20.1 for EPA’s estimates of 1999 fugitive dust emissions.

However, experts suggest that the current inventory 

has overstated these emissions, in part because of the 

multipliers that are used to infer the emissions of PM2.5

from PM10 monitoring data (Pace, 2005). (For example, 

a multiplier of 0.20 would imply that PM2.5 accounts for 

20 percent of PM10 emissions.) Currently, EPA’s AP-42 

emissions factors are based on fi ne to coarse ratios ranging 

from 0.15 to 0.40 for most fugitive dust sources. However, 

a recent study by the Western Regional Air Partnership 

(WRAP) suggests a fi ne to coarse ratio of 0.10 for fugitive 

dust. According to WRAP, this bias helps explain why 

researchers often see a discrepancy in the proportion 

of fugitive dust found in PM2.5 emissions inventories as 

compared to the proportion on ambient fi lter samples 

(WRAP, 2005). Sources also suggest that sampling 

methods may be overstating the PM10 emissions rates of 

agricultural sources and other categories, from which 

the PM2.5 estimates are derived (WRAP, 2005; Comis, 

2004). Efforts to estimate the fi ne to coarse ratio and to 

address other fugitive emissions factor issues continue and 

will likely continue to evolve subsequent to publication 

of this report. Nevertheless, given that fugitive dust is a 

Chapter 20

Fugitive Dust
 Chapter 20 - Fugitive Dust 275

major component of the direct PM2.5 inventory, controlling 

emissions from paved and unpaved roads can be an 

effective way of reducing an area’s direct PM2.5 emissions.

In the discussion that follows, we focus on the options 

for reducing PM emissions from paved and unpaved 

roads (including construction sites) and from agricultural 

sources. Additional options beyond the strategies 

discussed in this chapter are available for reducing 

emissions from construction and demolition activities.

Profi le: Paved and Unpaved Roads

According to the Federal Highway Administration, 

there are nearly four million miles of roads in the U.S. 

(DOT, 2002a). Roads cover more than 1 percent of the 

country, an area the size of South Carolina (DOT, 2002a; 

Gewertz, 2003). Sixty-three percent of this total is paved 

(2.50 million miles), with the other 37 percent unpaved 

(1.45 million miles) (DOT, 2002b). In 1999, American 

automobiles traveled nearly 1.6 trillion miles, or an average 

of 5,704 miles per capita.

Paved Roads

Paved roads generate PM emissions when motor vehicles 

and wind cause loose material from the road (including 

brake and tire wear) to be suspended above the road’s 

surface. The loose material, known as “surface loading,” 

is replenished by various sources, such as snow and ice 

removal compounds, erosion from adjacent areas and 

other debris (EPA, 2003a). Trucks carrying dirt and other 

materials can also contribute to surface loading as a result 

of spillage, and cars and trucks contribute “trackout” from 

unpaved roads and work areas. Trackout is the deposition 

of mud, dirt or similar debris onto the surface of a paved 

road from the tires and undercarriage of a motor vehicle.

The quantity of emissions that a road generates depends 

on the speed of the vehicles traveling the road, the traffi c 

levels, the fraction of heavy vehicles (buses and trucks), 

and the presence or absence of parking lanes and curbs 

(EPA, 2003a). Emissions from paved roads also vary with 

the silt loading of the road. Silt loading refers to the mass 

of silt-size material (under 75 μm in physical diameter) per 

area of travel surface (EPA, 2003a). In the colder regions 

of the country, road surface loadings are heaviest during 

the late winter and early spring months, when the residual 

loading from snow and ice controls is greatest. In warmer 

weather, when snow and ice controls are no longer used, 

the road surface loadings decline signifi cantly (EPA, 

2003a).

EPA’s PM emissions estimation methodology for 

fugitive dust from paved roads is in Section 13.2.1 of 

AP-42 and was last updated in December 2003. Section 

7.9 of the California Air Resources Board (CARB) 

Emission Inventory Methodology provides an alternative 

methodology for estimating PM emissions from paved 

roads. CARB’s methodology was last updated in July 

1997.

Unpaved Roads

Vehicles traveling on unpaved roads pulverize the road, 

generating particles that are lifted and dropped from the 

rolling wheels. At the same time, strong air currents from 

the vehicle act on the disturbed road surface, and the wake 

continues to generate particles even after the vehicle has 

passed.

As with paved roads, PM emissions from unpaved roads 

vary directly with the fraction of silt particles present on 

the road surface. However, while paved roads have silt 

material from external sources, unpaved roads possess 

silt inherently: the road itself is the source of emissions in 

addition to any surface loading (EPA, 1992). The range 

Table 20.1

PM2.5 Emissions: Fugitive Dust and Agricultural Burning Sources (1999)

Source Category PM2.5 Emissions (Tons) Percent of Source Category Emissions (%)

Unpaved roads 1,303,858 37

Paved roads 687,856 20

Agriculture (crop production) 861,172 25

Agriculture (livestock) 88,324 3

Agricultural burning 151,816 4

Construction 384,649 11

Total 3,477,675 100

Source: EPA, 2005c
276 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

of silt content for different types of unpaved roads can 

vary over two orders of magnitude, depending on the soil 

characteristics and meteorology of the area. Moisture, in 

particular, plays a signifi cant role in this regard, as water 

acts as a dust suppressant (WRAP, 2004). The types of 

vehicles traveling on the road also infl uence emissions. 

Emissions are highly correlated with vehicle weight, so 

that roads near industrial sites have higher emissions. In 

areas with fewer heavy vehicles, the moisture content of 

the road is likely to be the dominant factor in determining 

emissions (EPA, 2003b).

Profi le: Agricultural Sources

Roughly half of all land in the lower 48 states is farmland, 

including cropland, land in the Conservation Reserve 

Program (discussed below), pastureland and rangeland. 

Both crop and animal production generate pollutants that 

enter the air and the surface and ground waters (Hopkins, 

2004). Agricultural operations generate fugitive dust 

from four primary sources: wind erosion, tillage (soil 

preparation), livestock operations and agricultural 

burning.

Wind generates agricultural dust as it blows across dry, 

exposed soil. The levels of dust generated depend on wind 

speed, moisture content of the soil, vegetative cover and 

the composition of the soil. Tillage operations can increase 

the concentrations of dust in the air as farm machinery 

disturbs the soil. As one would expect, loose, dry soil 

is much more apt to be swept up during mechanical 

disturbances or windy conditions (WRAP, 2004; USDA, 

2000).

Livestock operations generate PM emissions from several 

sources. For instance, in outdoor operations, animals 

kick up dust simply by walking on dry soil and manure. 

Manure piles are prone to dust formation during windy 

conditions. Bedding materials, low-moisture feedstuffs 

(such as hay), animal dander and poultry feathers are also 

sources of emissions. The emissions rates from these 

sources are highly variable and depend on a variety of 

factors: the moisture content of the soil and manure (which 

depends, in turn, on precipitation and watering practices), 

the degree of exposure of manure piles to wind, the type 

of ventilation in indoor facilities and other factors (USDA, 

2000).

Farms use agricultural burning to reduce or dispose of 

vegetative debris. Some farm operators burn large areas of 

land following the harvest to reduce excess plant material; 

to control crop diseases, weeds and pests; and to maintain 

crop yields. Farm operators also burn piles of agricultural 

debris, such as orchard trees, limbs and haystacks, and use 

fi re to clear vegetation out of irrigation ditches and canals 

(USDA, 2000; EPA, 2005b). Agricultural burning, like 

any biomass combustion, produces direct emissions of 

PM2.5 as well as smaller amounts of sulfur dioxide (SO2) 

and nitrogen oxides (NOx).

Emission Control Opportunities: 

Paved and Unpaved Roads

There are two basic options for controlling fugitive PM 

emissions from paved roads: (1) prevention strategies 

aimed at reducing the transport and deposition of material 

on roadways; and (2) mitigation strategies that seek to 

remove the material after it has been deposited on the 

road surface. Prevention is generally the preferred option; 

however, some situations can only be addressed with 

mitigation measures (EPA, 1992). Unpaved roads can 

be addressed with surface improvements (i.e., paving) 

or surface treatments. According to WRAP, the control 

effi ciencies for various options are highly variable (WRAP, 

2004).

It is important to recognize that not all control options are 

equally cost-effective or appropriate in all areas. Costeffectiveness will vary depending upon the number, size, 

and confi guration of sources within a jurisdiction, and the 

contribution of that source to local PM concentrations. 

Cost-effectiveness is also dependent upon the existing 

degree of control for a given source type. Therefore, 

cost-effectiveness will vary depending upon the baseline 

or starting point in each area. The cost-effectiveness 

numbers offered in this chapter are given as examples 

only.

Table 20.2 summarizes the cost-effectiveness of a variety 

of control options that were evaluated on behalf of the 

San Joaquin Valley Unifi ed Air Pollution Control District 

(UAPCD). Cost-effectiveness estimates vary by several 

fold. The estimates were reported only for PM10, and the 

cost-effectiveness of controlling PM2.5 could be many 

times higher than the estimates in Table 20.2 because the 

proportion of PM2.5 in fugitive dust is small compared to 

the total concentration of PM10, as noted previously. For 

example, the WRAP Fugitive Dust Handbook provides 

a sample calculation of the cost-effectiveness of street 

sweeping using a PM10-effi cient sweeper. WRAP 

estimates that it would cost $960 per ton of PM10 reduced 

to sweep an arterial road once per month (making various 

site-specifi c assumptions about the number of vehicles per 

day, average vehicle speeds, road length, etc.). In contrast, 

the cost of controlling PM2.5 using the same control 

measure is more than four times greater ($3,930 per ton 

of PM2.5 reduced) (WRAP, 2004). In general, control 

strategies aimed at reducing fugitive dust seek to reduce 

PM10 emissions, and in some cases data are not available 

regarding the effectiveness of these control options for 

reducing PM2.5.
 Chapter 20 - Fugitive Dust 277

Prevention Measures for Paved Roads

As indicated, prevention measures seek to reduce the 

amount of material deposited on roadway surfaces, 

including anti-skid materials used during the winter 

months, soil material from unpaved road shoulders, and 

mud and dirt carryout from construction sites and unpaved 

roads. Strategies are available for addressing each of these 

sources.

Silt loading from anti-skid materials can be a signifi cant 

source of fugitive dust, at times causing a multi-fold 

increase in total PM10 emissions, although not necessarily 

in PM2.5 (EPA, 1992, 2003c). EPA has found that anti-skid 

materials are frequently applied well above recommended 

levels (EPA, 1992). Reducing the application of sanding 

materials is one option for reducing fugitive dust. A 

second option is to rely on harder or coarser materials 

that have a lower initial silt content or greater resistance 

to forming silt-size particles. For example, the Steamboat 

Springs, Colorado area requires the use of street sanding 

materials with less than 2 percent fi nes (EPA, 2004). This 

option is limited by price and availability (EPA, 1992). A 

recent study conducted at Lake Tahoe, Nevada suggests 

that switching to liquid de-icers can reduce road dust 

emissions (Gertler, 2005). Finally, improved planning 

and application techniques can also reduce emissions. 

For example, offi cials can limit the application of antiskid material to intersections, hills, and curves as safety 

permits (EPA, 1992). 

Unpaved road shoulders (i.e., the edges of the road) can be 

a major source of road dust, particularly in arid regions of 

the country (EPA, 1992). Passing vehicles, wind erosion 

and water runoff transport dust from the exposed shoulder 

to the roadway. The dust loadings from uncurbed 

Table 20.2

Control Effi ciencies for Roadway Control Measures (2002$)

Control Measure Cost-effectiveness 

(dollar per ton of PM10)

Paved Roads

Require 4 foot paved shoulders on all new or modifi ed paved roads $13,800 - $554,000

Require 4 foot paved shoulders on 50% of existing paved roads with highest traffi c $7,290 - $11,300

Require streets to be swept by PM10-effi cient street sweepers once per month $1,070

Require wind- and water-borne deposition to be removed within 24 hours of discovery $2,850

Limit the purchase of new street sweepers to PM10-effi cient units $33

Trackout

Install gravel bed trackout apron (3 inches deep, 50 feet long and full road width) $13,700 - $322,000

Install a pipe grid trackout control device. $44,100 - $387,000

Require paved interior roads to be 100 feet long and full road width $7,930 - $186,000

Unpaved Roads

Limit maximum speed on unpaved roads to 25 miles per hour $1,080

Pave unpaved roads and unpaved parking areas $2,160 - $5,920

Implement watering twice a day for industrial unpaved roads unknown

Apply dust suppressant annually to unpaved parking areas unknown

Require paving, 4 inches of gravel or dust suppressants to maintain stabilization surfaces 

at special event parking

$5,980 - $63,200

Implement measures aimed at limiting visible dust emissions to 20% opacity on unpaved 

parking areas receiving up to 100 trips per day

$5,230 - $30,500

Source: San Joaquin Valley UAPCD, 2003
278 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

shoulders are estimated to be many times greater than 

those from curbed streets (EPA, 1992).

Paving road shoulders is one option for reducing particle 

loadings. According to published reports, the cost of 

constructing a 4-foot wide paved shoulder is approximately 

$66,000 per mile (both directions), plus maintenance. 

According to an assessment prepared for the San Joaquin 

Valley UAPCD, paving costs range from $13,800–

$554,000 per ton of PM10 reduced (2002$), depending on 

the amount of traffi c. A lightly traveled road reduces the 

cost-effectiveness of this approach (San Joaquin Valley 

UAPCD, 2003). (These estimates do not refl ect the lifecycle impact of manufacturing and applying paving 

materials.) The effectiveness of curbing is greater when 

the adjacent soil is stabilized or covered to prevent wind 

erosion or tracking onto the street. Wind fences can also 

be effective in reducing road dust (EPA, 1992).

Mud and dirt carryout from unpaved areas, such as parking 

lots and construction sites, can generate a signifi cant share 

of paved road silt loadings (EPA, 1992). Control options 

include securely covering the tops of trucks carrying dustprone materials; spraying the tires of vehicles as they leave 

unpaved areas; installing a gravel bed trackout to remove 

dirt and mud from vehicle tires; and installing pipe or grate 

grid trackout devices, which can also be used to remove 

dirt from tires.

A gravel bed trackout device consists of a layer of washed 

gravel, rock or crushed rock at the intersection of a paved 

roadway and a work site entrance, to dislodge mud, dirt 

and debris from the tires of motor vehicles before they 

leave the work site. The cost of a gravel bed trackout 

device is estimated at $500 to construct and $860 per year 

to maintain (2002$). Maintenance includes the periodic 

removal, screening and replacement of the gravel to remove 

accumulated soil (San Joaquin Valley UAPCD, 2003). 

Based on a control effi ciency of 46 percent, the costs are 

estimated to range from $13,700–$322,000 per ton of PM10

reduced. This wide range stems from the assumptions that 

are made with regard to the number of vehicles exiting 

the worksite, which infl uences the level of emissions 

attributable to the trackout, as well as the assumptions 

regarding the amount of soil trackout generated by an 

individual vehicle (San Joaquin Valley UAPCD, 2003). 

The WRAP Fugitive Dust Handbook provides a sample 

calculation of the cost-effectiveness of installing a 25 foot 

gravel apron at a construction site. The cost-effectiveness 

for the control of PM10 emissions is estimated at $45,000 

per ton. The cost-effectiveness for the control of PM2.5

emissions is estimated at $225,000 per ton (WRAP, 2004).

Another alternative is a pipe grid system—sometimes 

called a grizzly—that shakes the accumulated dirt 

and mud from trucks leaving a construction site. The 

device consists of a series of steel pipes welded into a 

ladder-like formation. A pipe grid system is estimated 

to reduce trackout by 80 percent. Cost estimates range 

from $44,100–$387,000 per ton of PM10 reduced (2002$), 

depending on the assumptions that are made regarding the 

quantity of emissions that are generated by trackout (San 

Joaquin Valley UAPCD, 2003).

Mitigation Measures for Paved Roads

Several cities use road cleaning, either by sweeping or 

water fl ushing, as a strategy for reducing PM10 emissions. 

Originally, street sweeping was performed exclusively for 

cosmetic reasons; however, air pollution and stormwater 

regulations have expanded the practice and have led to the 

development of new technologies. 

The effectiveness of street cleaning as an air pollution 

control strategy, however, is limited in several respects. 

Street sweeping equipment varies in terms of its controleffectiveness and may, in some cases, actually increase 

PM10 emissions (DOT, 2005). By sweeping gutters 

and curb areas, a street sweeper may actually transfer 

the loose particles to the traveled portion of the road, 

resulting in a short-term increase in emissions (WRAP, 

2004; Kuhns, 2003; Gertler, 2005). Several factors can 

limit the effectiveness of street sweeping: the presence 

of parked cars and traffi c congestion during sweeping, 

poor road surface and curb conditions and the presence of 

construction projects nearby. Also, the cycle of particle 

deposition on road surfaces and subsequent resuspension 

in the air will generally outpace efforts to keep the roads 

swept, thereby limiting its effectiveness as a control 

option. 

Targeted efforts to eliminate anti-skid materials or the 

cleanup of mud and dirt from road surfaces following a 

wind or rain event are likely to offer the best opportunities 

for application of the technology.

There are three basic options in street sweeping 

technology: traditional mechanical sweepers, vacuum 

assisted sweepers and regenerative air sweepers.

Mechanical sweepers employ a rotating gutter broom 

to remove particles from the street gutter area, with 

a water spray used to control dust. The particles are 

then placed in the path of a cylindrical broom that 

rotates to carry the material onto a conveyor belt and 

into a storage hopper. This is the most widely used 

equipment for street cleaning in the U.S.

Vacuum assisted sweepers also use gutter brooms to 

remove particles from the street. However, the refuse 

is then placed in the path of a vacuum intake that 

sucks the dirt into the hopper. The transported dirt is 

usually saturated with water. The overall effi ciency 

of vacuum assisted cleaners is generally higher than 

•

•
 Chapter 20 - Fugitive Dust 279

that of mechanical cleaners, especially for particles 

larger than the dust and dirt range (larger than about 

3 millimeters).

Regenerative air sweepers blow air onto the pavement 

and immediately vacuum it back, to entrain and 

capture accumulated sediments. Air is regenerated 

for blowing through a dust separation system.

Street sweepers are most effective when operated at 

optimal speeds (six to eight miles per hour (mph)), brushes 

are properly adjusted and appropriate rotation rates and 

sweeping patterns are used.

The South Coast Air Quality Management District 

(AQMD) in California was the fi rst agency in the country 

to enact regulations that included an emissions standard 

for street sweepers (Rule 1186). South Coast AQMD 

certifi es street sweepers that satisfy minimum pickup and 

entrainment standards. South Coast AQMD-certifi ed 

street sweepers are listed at: www.aqmd.gov/rules/doc/

r1186/r1186_equip.pdf. South Coast AQMD has certifi ed 

mechanical sweepers, vacuum assisted sweepers and 

regenerative air sweepers. The purchase price of a 

certifi ed PM10-effi cient street sweeper is reported to be 

similar to that of a non-certifi ed unit, and the operating 

costs are approximately the same (San Joaquin Valley 

UAPCD, 2003).

The city of Toronto, Ontario has also developed a PM test 

protocol for street sweepers, concluding that regenerative 

air street sweepers are most effective in terms of PM10 and 

PM2.5 capture effi ciency. City offi cials tested eight street 

sweeper models, which included several mechanical, 

vacuum assist and regenerative air models (www.toronto.

ca/legdocs/2005/agendas/committees/wks/wks051108/

it014.pdf).

Unpaved Roads

The primary control options for fugitive dust from unpaved 

roads are surface improvements and surface treatments. 

Limiting the amount and speed of traffi c on unpaved roads 

can also be effective strategies for controlling emissions 

(EPA, 1992).

Surface improvements are generally one-time or infrequent 

affairs, unlike surface treatments, which must be reapplied 

periodically. The most obvious surface improvement 

is paving; however, because of its high cost, paving is 

only cost-effective on roads with relatively high traffi c 

volumes. Sources estimate the cost of paving an unpaved 

road at approximately $400,000 per mile, inclusive of 

roadway excavation, aggregate base, striping and traffi c 

control (2002$). Over an assumed 25-year useful life, the 

annualized cost of paving is $44,100 per year per mile (San 

Joaquin Valley UAPCD, 2003). Moreover, while paving 

may be a viable option for certain roads, paving operations 

•

require large amounts of energy and themselves generate 

various emissions, including PM2.5. Some roads are 

impractical to pave either because they have poor bases 

on which to build or because they experience substantial 

spillage from trucks. Because of the spillage and ensuing 

dust loading, such roads—even if paved—would still 

generate signifi cant emissions.

Another option for controlling PM emissions from 

unpaved roads is to cover the road with a material of 

lower silt content. For instance, covering a dirt road with 

gravel reduces dust emissions. This type of measure is 

initially much less expensive than paving, but has ongoing 

maintenance costs (grading, reapplication of gravel 

material). Finally, for roads with very low traffi c volume, 

vegetative cover is an option (EPA, 1992).

Surface treatments come in two types: wet suppression 

(i.e., watering) and chemical stabilization (EPA, 1992). 

Reapplication frequencies range from a few minutes 

for water treatments during a hot summer day to several 

weeks or months for chemical treatments.

The control effi ciency of watering unpaved roads depends 

on four factors: the amount of water applied per unit area 

of road surface, the time between applications, traffi c 

volume during that period and prevailing meteorological 

conditions. EPA fi eld tests suggest low control effi ciency 

(the actual numbers are not explicitly stated) and the need 

for frequent (almost daily) reapplications (EPA, 1992). 

The WRAP Fugitive Dust Handbook provides a sample 

calculation of the cost-effectiveness of watering (twice 

daily) the unpaved roads of an industrial facility. WRAP 

estimates a cost of $530 per ton of PM10 reduced and a cost 

of $3,450 per ton of PM2.5 reduced (WRAP, 2004). 

Chemical treatments, which can be more effective, simulate 

wet suppression by attracting and retaining moisture on 

the road surface. Watering often supplements chemical 

treatments. Most chemical suppressants form a hard 

cemented surface. The most common type is a petroleum 

resin, but asphalt emulsions, acrylics and adhesives are 

also options (EPA, 1992). Potential environmental impacts 

include surface and groundwater quality deterioration, soil 

contamination, toxicity to soil and water biota, toxicity to 

humans during and after application, air pollution from 

volatile dust suppressant components, accumulation in 

soils, changes in hydrologic characteristics of the soils, 

and impacts on native fl ora and fauna populations.

Emission Control Opportunities: 

Agricultural Operations

Because of the diversity of agricultural activities and 

conditions that generate fugitive dust (i.e., tilling, wind 
280 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

erosion, animal operations and agricultural burning), the 

control opportunities are also varied.

Tillage

The primary options to reduce fugitive dust from tillage 

involve limiting activity during windy conditions and 

reducing tillage in various ways. The tillage methods 

described in Table 20.3 differ in the amount of soil 

disturbed and the amount of crop residue allowed to 

remain before the next planting (EPA, 2000). 

Conservation tillage methods reduce soil erosion by 

allowing soil and crop residue to remain undisturbed. 

Some common methods include no-till, strip-till, ridge-till 

and mulch-till (EPA, 2000).

No-till has minimal soil disturbance because the seed 

is planted with essentially no tillage of the soil and no 

disturbance of the crop residue.

Strip-till involves tillage of a narrow strip of soil and 

planting of the seed or seedling in the tilled area.

Ridge-till methods disturb a narrow strip of soil that 

was created during previous cultivation. The crop 

is planted on the ridge and the crop residue remains 

•

•

•

between each ridge.

Mulch-till involves distributing loose plant residue 

across a fi eld to reduce wind erosion and to conserve 

soil moisture (EPA, 2000).

Other techniques can also reduce tillage. For instance, 

the California Air Pollution Control Offi cers Association 

(CAPCOA) recommends combining operations to perform 

several operations during one pass, altering the bed or row 

size and spacing to reduce the number of passes and soil 

disturbances by increasing plant density, operating at night 

when moisture levels are higher and winds are generally 

lighter, and applying or leaving plant residue on the soil 

surface to reduce wind erosion of soil (CAPCOA, 2004).

EPA has also suggested using a punch planter to reduce 

emissions from planting cotton, corn and lettuce (EPA, 

1992). A punch planter punches a hole and places the seed 

into it, as opposed to conventional planters that make a 

trough and drop the seeds in at a specifi ed spacing. Punch 

planters leave much of the surface soil and surface crop 

residues intact. However, large-scale use would require 

substantial investment.

Planing (fl attening the land) and its associated emissions 

can be reduced in two ways. The fi rst is to use sprinkler 

•

Table 20.3

Effi ciency for Various Control Options for Tillage Operations

Control Measure

PM10 Control 

Effi ciency References/Comments

Limited activity during 

high winds

1%–5% SCAQMD, 1997. Control effi ciency assumes no tilling when wind 

speed exceeds 25 miles per hour.

Reduced tillage system 

(conservation tilling)

35%–50% Coates, 1994. This study identifi ed total PM10 emissions generated 

by fi ve different cotton tillage systems, including conventional tillage 

systems. Four of the systems combine several tillage operations (e.g., 

shredding, disking, mulching).

60% MRI, 1981. Control effi ciency is for a minimum tillage technique that 

confi nes farm equipment and vehicle traffi c to specifi c areas (for cotton 

and tomatoes).

30% MRI, 1981; EPA, 1992. Control effi ciency is for laser-directed land 

plane that reduces the amount of land planing.

50% MRI, 1981; EPA, 1992. Control effi ciency is for using punch planter 

instead of harrowing (for cotton, corn and lettuce).

50% MRI, 1981. Control effi ciency is for using plug planting that places 

plants more exactly and eliminates the need for thinning (for tomatoes 

only).

50% MRI, 1981; EPA, 1992. Control effi ciency is for aerial seeding, which 

produces less dust than ground planting (for alfalfa and wheat).

91%–99% Grantz, 1998. Control effi ciency is for revegetation of fallow agricultural 

lands by direct seeding.

Source: WRAP, 2004
 Chapter 20 - Fugitive Dust 281

irrigation in place of surface watering, since the latter 

requires completely fl at land. The second method is to 

use a laser-directed land plane, which has been used in the 

construction industry for decades. With a more precise 

leveling blade, the amount of land planing can be reduced. 

However, both of these options may require substantial upfront capital expenditures (EPA, 1992).

Finally, aerial seeding, or dropping seeds from an airplane, 

can be an effective way to reduce dust formation. Because 

of the expense, this technique is rare, although specifi c 

conditions may warrant its consideration. For example, 

a consortium including the University of California 

Cooperative Extension, the U.S. Department of Agriculture 

(USDA) Natural Resources Conservation Service and 

local air pollution districts instituted an aerial re-seeding 

program in the early 1990s, after a long drought during the 

previous decade reduced vegetation cover in the Mojave 

Desert. During the drought, dust storms had destroyed 

crops and forced farmers to re-seed frequently. Moreover, 

suspended soil had blown into surrounding areas and 

caused unhealthy PM10 levels. The resulting collaboration 

involved fi re department helicopters planting 2,500 

acres of severely degraded land. The maximum daily 

PM10 concentration in one town was reduced from 780 

micrograms per cubic meter of air in 1991 to an average of 

75.6 during the next ten years, and when drought returned 

in the late 1990s, the revegetation held the soil in place 

(Grantz, 2005).

Wind Erosion

Several options are available to reduce wind erosion. The 

oldest and perhaps easiest is the use of cover crops to 

cover soil surfaces that would otherwise be exposed and 

at risk of erosion. Cover plants include traditional crops, 

such as grasses, wheat, sorghum, corn, legumes and 

cotton (EPA, 1992). Cover crops such as rye are especially 

useful because they grow in late fall and provide soil cover 

during winter. 

Cover crops can be effective in reducing erosion, achieving 

over 90 percent control effi ciencies (Grantz, 1998; WRAP, 

2004). However, revegetation can be diffi cult to achieve in 

any given year, as varying environmental conditions and 

soil factors make direct seeding unreliable, and employing 

nursery-grown shrubs does not guarantee success, even 

with supplemental irrigation (Grantz, 1998).

Mulching can also prevent wind erosion. Mulching and 

spreading crop residues can be used in conjunction with 

cover crops, covering soil until the crops have a chance 

to take root. However, mulching does not last as long as 

cover crops and can be more vulnerable to wind if the 

mulch layer is shallow.

Windbreaks or barriers are another option for reducing 

wind erosion. Shrubs, trees and even manmade fences are 

effective wind barriers. Grass barriers also work well, but 

they do not slow the wind as much as shrubs or trees. The 

principle behind a wind fence or barrier is straightforward: 

it blocks soil from eroding and provides an area of 

reduced wind velocity to allow particles in the air to settle. 

Windbreaks generally consist of trees or shrubs, usually in 

multiple rows. The effectiveness of the barrier depends on 

the wind velocity and direction, shape, width, height and 

porosity of the barrier (EPA, 1992). 

Artifi cial barriers, such as fences constructed of board, 

bamboo, willow, rock or earth, are effective in reducing 

wind erosion. Their drawback is the high cost of material 

Table 20.4

Effi ciency of Control Options for Wind Erosion on Agricultural Lands

Control Measure PM10 Control Effi ciency References/Comments

Artifi cial wind barrier 64%–88%

54%–71%

4%–32%

EPA, 1992. Assumes a 50% porosity fence.

Grantz, 1998. Control effi ciency is for a wind fence.

Bilbro and Stout, 1999. Control effi ciency based upon reduction in 

wind velocity by a wind fence made from plastic pipe.

Cover crop 90% Washington State University, 1998.

Cross-wind ridges 24%–93%

40%–80%

Grantz, 1998. Control effi ciency is for furrows.

Washington State University, 1998.

Mulching 20%–40% Washington State University, 1998.

Trees or shrubs planted 

as a windbreak

25% Sierra Research, 1997. Control effi ciency is for trees.

Source: WRAP, 2004
282 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

and preferably 10–12, inches (ISU, 2004).

Altering the feed can also reduce emissions. For instance, 

because some dry, fi ne-grain feed generates dust emissions 

during handling and delivery, using higher-moisture feed, 

agglomerating the feed into pellets, or mixing the feed 

with vegetable oil or animal fats can reduce emissions. In 

addition, using enclosed feed delivery systems and covered 

feeders can cut emissions (EPA, 2001). Evidence suggests 

that altering the feed may also change fecal characteristics, 

thereby preventing dust emissions. For example, studies 

with pigs and cattle show that by adding fat or oil to the 

diets, feces become stickier and generate less dust (ISU, 

2004).

For indoor facilities, a number of options exist to reduce 

particulate emissions. Perhaps the easiest is to spray 

vegetable oil on fl oors and other surfaces (ISU, 2004; EPA, 

2001). The oil agglomerates the particles and prevents 

them from becoming airborne. However, while vegetable 

oil is generally inexpensive, one drawback to this approach 

is the increased safety (i.e., slipping) concern for animals 

and workers.

Another approach is to use fi ltration. Mechanical fi lters 

can be applied to building exhaust from totally or partially 

enclosed housing. Some fi ltration systems employ natural 

materials, such as straw or other crop residues, as the 

fi lter medium. However, mechanical fi lters eventually 

become clogged and need cleaning or replacement (EPA, 

2001). Another type of fi ltration is the use of trees, 

shrubs and walls as windbreaks or biofi lters (ISU, 2004). 

These techniques are similar to those discussed above for 

agricultural erosion control.

Ionization, used in electrostatic precipitators (ESPs), is 

another possibility for indoor animal operations. With 

ionization, gas molecules (e.g., oxygen) acquire a charge 

from high-energy electrons created by an electric fi eld. 

The ionized gases adhere to particulates, which then move 

to the nearest grounded surface (e.g., building surface, 

grounded collection plate) (EPA, 2001). ESPs used in 

other industries have achieved control effi ciencies of 

upwards of 99 percent, but three studies of agricultural 

operations achieved only 40-60 percent reductions. The 

researchers were unable to give defi nitive explanations for 

this discrepancy, but the high moisture content of the air 

stream may have been a factor (EPA, 2001).

Finally, a wet scrubber, described elsewhere in this 

document, can be an effective way to reduce emissions. In 

the context of animal feeding operations, a wet scrubber 

can be installed on the ventilation unit. While wet 

scrubbers have not been used extensively in the industry, 

one study showed a 90 percent reduction of total PM (EPA, 

2001).

and labor required for construction. As a result, their 

use has been limited in the U.S. and confi ned to areas 

with high-value crops or where overpopulation requires 

intensive agriculture (EPA, 1992). 

Another technique is cross-wind ridges or stripcropping. Strip-cropping entails establishing crops in 

strips perpendicular to the prevailing wind direction 

and arranging crops so that strips susceptible to wind 

erosion are alternated with strips resistant to wind erosion 

(CAPCOA, 2004).

Finally, roughening the surface by using tilling methods 

that leave stable clods of soil is a simple control technique 

that can substantially reduce fugitive dust (CAPCOA, 

2004).

Animal Operations

A host of control options are available to reduce fugitive 

dust from animal operations, including planting trees 

and shrubs; maintaining feedlots by removing manure; 

covering manure piles; and reducing animal activity 

during the late afternoon, when dust is most likely to form 

(ISU, 2004). Despite the various control options available, 

few have been tested extensively, and data on cost and 

effectiveness, especially for PM2.5, are scarce.

The application of water can reduce fugitive dust from 

outdoor facilities. Facilities employing this method 

generally rely on a tanker truck to dispense water. EPA 

notes that this technique may be practical only for small 

operations, since a large amount of water is needed—one 

study estimates the amount of water to be equal to cattle 

drinking-water requirements during the dry season (EPA, 

2001). Another potential drawback is that high moisture 

content can lead to odor problems and may also induce 

greater microbial activity (although no data have yet shown 

this to be the case). Indoor facilities have not conducted 

any studies using sprinklers to reduce PM2.5 emissions, 

but misting systems are already in place in some poultry 

and swine operations, indicating that water sprays do have 

potential in an indoor context (EPA, 2001).

Covering manure stockpiles is another method to 

reduce PM2.5 emissions. Impermeable covers, such as 

polyethylene, can provide substantial reductions. These 

covers, which range in cost from $1.00–$1.40 per square 

foot (installed), last about ten years, but they eventually 

degrade due to snow and wind damage (ISU, 2004). At 

that point the small bits of plastic shed by the cover can 

become an environmental and aesthetic problem, not to 

mention a nuisance. Permeable covers, such as straw, 

cornstalks, peat moss, foam, rocks and fabric, can also be 

effective. Costs vary widely, from $0.10 per square foot 

(applied) for straw and cornstalk, to $0.26 for peat moss. 

Iowa State University recommends a depth of at least 8, 
 Chapter 20 - Fugitive Dust 283

Agricultural Burning

Agricultural burning can produce large quantities of smoke 

in a short period of time. To reduce impacts, permits are 

usually required before burns can be conducted. These 

permits can restrict the type and amount of agricultural 

material burned and limit burning to those times when air 

quality and meteorological conditions are most suitable for 

reducing impacts (EPA, 2005b). Alternatives to burning 

should also be investigated as the situation permits. 

Regulatory Authority

Federal law does not regulate fugitive dust directly. 

However, state and local authorities have adopted 

programs to control fugitive dust in an effort to comply 

with the national PM10 air quality standards.

The Clean Air Act requires states to develop plans that 

include all Reasonably Available Control Measures 

(RACM) or all Best Available Control Measures 

(BACM), including fugitive dust control measures, in 

PM10 nonattainment areas. For example, the South Coast 

AQMD requires all fugitive dust sources to implement 

specifi c control measures to prevent visible dust emissions 

from crossing any property line (Rule 403). Studies 

indicate that approximately one-third of the South Coast 

basin’s ambient PM10 concentrations and over 90 percent 

of Coachella Valley’s ambient PM10 levels are the result of 

fugitive dust (South Coast AQMD, 2005).

In support of the states’ effort to implement BACM, EPA 

has developed guidance on the control measures available 

for reducing fugitive dust (EPA, 1992). More recently, the 

San Joaquin Valley UAPCD published an evaluation of 

BACM, focusing on fugitive dust emissions (San Joaquin 

Valley Unifi ed APCD, 2003).

Many of the federal programs that regulate agricultural 

operations are not directed at air emissions (e.g, the Food 

Quality Protection Act of 1996). However, there are 

voluntary programs that impinge on agriculture-related 

air quality issues. The Conservation Reserve Program 

within the USDA pays farmers to apply soil and water 

conservation measures and to keep highly erodible and 

other types of land out of production. The contracts 

generally last for 10–15 years. At the end of 2004, there 

were nearly 400,000 farms participating in the program, 

covering 35 million acres (USDA, 2005a, 2005b). Soil 

conservation practices are often consistent with efforts to 

control fugitive dust emissions.

Also, the USDA has evaluated options for reducing 

fugitive dust emissions from agricultural operations under 

the auspices of its air quality program.1

1. More information is available at www.ars.usda.gov/research/programs.htm.

State and Local Opportunities

The San Joaquin Valley UAPCD in California; Clark 

County, Nevada; and Maricopa County, Arizona have 

implemented programs to control fugitive dust emissions 

from paved and unpaved roads. Toronto, Ontario has 

evaluated the PM2.5 control effectiveness of street 

sweepers. Few states have regulated agricultural activities 

as a means of complying with air quality standards.

Paved Roads

San Joaquin Valley, California. Rule 8061 of the 

San Joaquin Valley UAPCD (amended August 19, 2004) 

requires new paved roads or modifi cations to existing 

paved roads with projected annual average daily vehicle 

trips of 500 vehicles or more to be constructed with paved 

shoulders at least 4 feet wide, or the limit of the right-ofway, whichever is smaller. Roads with over 3,000 vehicles 

per day must have 8-foot shoulders, or shoulders built to 

the limit of the right-of-way, whichever is smaller (San 

Joaquin Valley Unifi ed APCD, 2004).

As an alternative to meeting the shoulder width standard, 

areas may also install curbing next to the travel lane or 

construct intersections, auxiliary entry lanes and auxiliary 

exit lanes adjacent to the roadway (San Joaquin Valley 

Unifi ed APCD, 2004).

If a road is constructed (or modifi ed) with a median, the 

median must have a shoulder width of 4 feet adjacent to the 

travel lanes. This standard does not apply to roads with 

speed limits under 45 mph that have curbing. In addition, 

areas can avoid this requirement if they landscape and 

maintain their medians with grass or other vegetative 

ground cover or dust suppressants.

Rule 8061 also has requirements regarding PM10-effi cient 

street sweepers; it provides that as of July 1, 2005, all 

purchases of street sweeper equipment by an agency or 

its contractor must be only PM10-effi cient street sweepers, 

and that each agency or contractor must purchase and use 

at least one PM10-effi cient street sweeper by July 1, 2008. 

The rule also requires that the routine street sweeper routes 

with paved curbs and the greatest dirt and silt loadings 

be cleaned at least once per month. If these provisions 

cannot be met due to budgetary constraints, the agency 

may submit a statement of fi nancial hardship and request 

a waiver.

Finally, the rule specifi es actions that agencies must follow 

after an “event” that results in at least 1-inch thickness 

of mud or dirt over an area of at least 50 square feet as 

a result of runoff or erosion from wind, water or a storm. 

Within 24 hours after discovering this condition, the 

agency must remove the mud or dirt from the travel lanes 

or restrict vehicle travel until the material can be removed. 

The agency must follow dust minimizing practices when 
284 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

removing the dirt and must remove it from paved shoulders 

as soon as practicable. Time extensions are available for 

safety concerns.

Clark County, Nevada. Clark County, Nevada has 

promulgated regulations for paved roads. Section 93 of 

the county’s air quality regulations deals with fugitive dust 

from paved roads. The rule was initially adopted in June 

2000 and has been amended six times since, most recently 

on July 1, 2004 (Clark County, 2004a).

Like the San Joaquin Valley rule, §93 requires new 

construction and modifi cation of paved roads to have 4 feet 

of paved or stabilized (with gravel) shoulder for roads with 

average vehicular traffi c under 3,000 vehicles per day, and 

8 feet for roads with over 3,000 vehicles per day. If the 

right-of-way is not available for the full length (4 or 8 feet), 

curbing must be installed instead (Clark County, 2004a).

The rule also specifi es median requirements on newly 

constructed roads or roads modifi ed with shoulders or 

medians. Such roads must be constructed with one of the 

following control measures: curbing; solid paving across 

the median; dust palliatives; 2 inches of gravel; or other 

materials that prevent trackout, such as landscaping or 

decorative rock. The measures must achieve control of 

fugitive dust emissions under 20 percent opacity and silt 

loading under 0.33 ounces per square foot (Clark County, 

2004a).

Toronto, Ontario. The city of Toronto has developed 

a test protocol for street sweepers that evaluates both 

PM10 and PM2.5 control-effectiveness. The testing has 

examined the amount of material picked up and removed 

from the test track, redeposited on the sidewalk or road 

surface, and released into the air. The testing established 

that the regenerative-air street sweepers achieved the 

best performance for both PM10 and PM2.5 in all three test 

categories. The city has issued a request for proposals 

limited to regenerative air street sweeper technology, with 

specifi c performance thresholds developed based on the 

testing performed (Welsh, 2005).

Unpaved roads

San Joaquin Valley, California. Rule 8061 of the 

San Joaquin Valley UAPCD specifi es various measures 

for unpaved roads. First, the rule prohibits building new 

unpaved roads except for temporary purposes. Second, 

unpaved roads with over 25 vehicles per day must have a 

maximum speed limit of 25 mph and post speed limit signs 

once every mile in urban areas and once every 2 miles in 

rural areas.

In addition, the rule aims to limit visible dust emissions 

to 20 percent opacity by requiring unpaved roads with 

over 25 vehicles per day to implement one of a number 

of control measures. The measures include watering, 

installing a uniform layer of washed gravel, using chemical 

or organic dust stabilizers or suppressants, paving, or any 

other method that can achieve 20 percent opacity.

The rule also requires agencies with primary responsibility 

for a road to provide their air pollution control districts with 

a list of all unpaved roads and a list of paved roads with 

unpaved shoulders, together with their length and average 

daily vehicle traffi c. By January 1, 2010, each agency 

is required to pave an average of 20 percent annually of 

all unpaved roads (to a maximum of 5 cumulative miles 

within any one urban area), with priority given to roads 

with the highest vehicle traffi c. Also by January 1, 2010, 

urban areas must pave or stabilize 4-foot shoulders on 

50 percent of existing paved public roads with unpaved 

shoulders, and rural areas must do the same for 25 percent 

of roads with unpaved shoulders. Each year, the agency 

responsible for the road must submit a report detailing the 

number of unpaved road miles paved during the previous 

year. Areas with budget problems can request a waiver 

from these paving requirements. 

San Joaquin Valley UAPCD Rule 8021 limits fugitive 

dust emissions from construction, demolition, excavation, 

extraction and other earthmoving activities. The rule 

requires the application of water or chemical stabilizers/

dust suppressants, in conjunction with optional wind 

barriers, to limit visible dust emissions to 20 percent 

Table 20.5

Clark County, Nevada Compliance Schedule for Unpaved Roads

Nonattainment Area Fraction of Total Miles of Unpaved Roads Controlled

1⁄3 2⁄3 All

Basin 212a June 1, 2001 June 1, 2002 June 1, 2003

Basins 216 & 217b April 1, 2003 April 1, 2004 April 1, 2005

a. Applies to roads constructed prior to June 22, 2000. 

b. Applies to roads constructed prior to April 1, 2002.

Source: Clark County, 2004b
 Chapter 20 - Fugitive Dust 285

opacity. 

Clark County, Nevada. Clark County has stringent 

standards for unpaved roads. Section 91 of the county’s 

air quality regulations were initially adopted in June 2000 

and have been amended four times since, most recently on 

July 1, 2004. The rule prohibits the construction of new 

unpaved roads in specifi ed areas. It requires owners or 

operators of existing roads with at least 150 vehicles per 

day to pave the roads, apply dust palliatives, or apply and 

maintain an alternative control measure approved by the 

dates specifi ed in Table 20.5. In addition, new unpaved 

roads must apply dust control measures upon determining 

that they have more than 150 vehicles per day traveling the 

road (Clark County, 2004b).

Maricopa County, Arizona. Maricopa County, Arizona 

has promulgated regulations to control fugitive dust from 

unpaved roads in the county’s PM10 nonattainment area. 

Rule 310.01 regulates unpaved roads as well as open 

areas, vacant lots and unpaved parking lots. The rule was 

initially adopted in June 1999 and has been revised twice, 

most recently on February 17, 2005.

The rule requires the owner of unpaved roads (including 

alleys) with at least 150 vehicles per day to pave the roads, 

apply dust suppressants, or apply and maintain gravel. 

The control measures must achieve 20 percent opacity and 

keep silt loading under 0.33 ounces per square foot or keep 

silt content less than or equal to 6 percent.

Agricultural Operations 

California regulators have adopted measures to reduce 

fugitive dust from agricultural activities. Senate Bill 656, 

passed in 2003, aims to reduce public exposure to PM2.5

and PM10. The bill requires CARB, in consultation with 

local air pollution control and air quality management 

districts, to adopt a list of the most readily available, 

feasible and cost-effective control measures that can be 

implemented by local air districts to reduce PM2.5 and PM10

(CARB, 2005a). The list is based on rules, regulations, 

and programs existing in California as of January 1, 

2004. Using these measures, air districts were to develop 

implementation schedules by July 31, 2005. The list of 

options covers various sectors and sources, including 

agriculture. Among the options for reducing particulates 

from agricultural operations are the following:

Cease tilling/mulching activities when wind speeds 

are greater than 25 mph.

Limit fugitive dust from paved and unpaved roads 

and livestock operations by requiring: (1) the 

cessation of all hay grinding activities between 2 and 

5 p.m. if visible emissions extend more than 50 feet 

from a hay grinding source, and (2) the treatment 

of all unpaved access connections to livestock 

•

•

operations and unpaved feed lane access areas with 

either pavement, gravel (maintained to a depth of 4 

inches) or asphaltic road-base.

Reduce fugitive dust from livestock feed yards by 

requiring: (1) a dust plan that contains procedures 

assuring moisture factors between 20 percent and 40 

percent for manure in the top 3 inches of occupied 

pens; and (2) outlines manure management practices, 

including removal.

Establish guidelines for smoke management, 

emphasizing effective planning, coordinating among 

burners, using the most technically advanced air 

quality and meteorology burn management tools, 

and considering alternatives to open burning. 

Specifi cally, the guidelines require local air districts 

to develop smoke management programs that contain 

three basic components: (1) requirements for a burn 

authorization system; (2) requirements for smoke 

management plans by farms conducting prescribed 

burns; and (3) requirements for burn, no burn and 

marginal burn days (CARB, 2004).

References

American Farm Bureau Federation (AFBF). “Farm 

Bureau: Flawed Air Standards Would Choke Agriculture,” 

AFBF press release, July 22, 1997. www.fb.org/news/nr/

nr97/nr0722b.html.

California Air Pollution Control Offi cers Association 

(CAPCOA), Clearinghouse for Agriculture. Disking, 

Tilling, Land Preparation, December 27, 2004. www.

capcoa.org/Agclearinghouse/dust-disking-tilling-landprep-fi eld.html.

California Environmental Protection Agency, Air 

Resources Board (CARB). Emission Inventory 

Methodology, Section 7.4: Agricultural Land Preparation,

January 2003. www.arb.ca.gov/ei/areasrc/fullpdf/full7-

4.pdf.

California Environmental Protection Agency, Air 

Resources Board (CARB). Proposed List of Measures 

to Reduce Particulate Matter—PM10 and PM2.5

(Implementation of Senate Bill 656, Sher 2003), October 

18, 2004. www.arb.ca.gov/pm/pmmeasures/staff_report.

pdf.

California Environmental Protection Agency, Air 

Resources Board (CARB). Fact Sheet: Reducing 

Particulate Matter in California—Implementation of 

Senate Bill 656, March 8, 2005. www.arb.ca.gov/pm/

pmmeasures/sb656_fact_sheet.pdf. (2005a)

California Environmental Protection Agency, Air 

•

•
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Resources Board (CARB). SB 656 List of Air District 

Measures That Reduce Particulate Matter, accessed 

November 1, 2005, from: www.arb.ca.gov/pm/

pmmeasures/board_approved_list.pdf.

Clark County (NV). “Section 93: Fugitive Dust from 

Paved Roads and Street Sweeping Equipment,” Air Quality 

Regulations, July 1, 2004. www.co.clark.nv.us/air_quality/

Regs/SECT93%207-01-04.pdf. (2004a)

Clark County (NV). “Section 91: Fugitive Dust from 

Unpaved Roads, Unpaved Alleys, and Unpaved Easement 

Roads,” Air Quality Regulations, July 1, 2004. www.

co.clark.nv.us/air_quality/Regs/SECT91%207-01-04.pdf. 

(2004b)

Comis, Don. “A Bum Rap for Agriculture?” Agricultural 

Research, May 2004.

Fitz, D.R., K. Bumiller, A. Afan, and C. Bufalino. 

Measurement of PM10 Emission Factors from Paved Roads 

in Real-Time Using On-Board Particle Sensors (draft), 

December 2005.

Grantz, David, D.L. Vaughn, B. Kim, T. VanCuren, and 

D. Campbell. “Though Diffi cult To Achieve, Revegetation 

Is Best Way To Stabilize Soil,” “Wind Barriers Offer ShortTerm Solution to Fugitive Dust,” California Agriculture

52(4): 8-13, July-August, 1998.

Grantz, David, University of California, Riverside. 

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October 28, 2005, from: http://ucanr.org/delivers/

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Gillies, V. Etyemezian, R. Clayton, and D. Proffi tt. A Case 

Study of the Impact of Winter Road Sand/Salt and Street 

Sweeping on Road Dust Re-Entrainment (draft), December 

2005.

Gewertz, Ken. “Highway 61—and 93 and 128—Revisited: 

New Book Looks at What Can Be Done To Soften 

Environmental Impact of America’s Four Million Miles 

of Road,” Harvard University Gazette, January 23, 

2003. www.news.harvard.edu/gazette/2003/01.23/17-

roadecology.html.

Hayden, John and J. Richards. “TEOM-Based Measurement 

of Industrial Unpaved Road PM10, PM2.5, and PM10-2.5

Emission Factors,” 14th International Emission Inventory 

Conference: Transforming Emission Inventories—Meeting 

Future Challenges Today, April 11-14, 2005. www.epa.

gov/ttn/chief/conference/ei14/index.html.

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State and Territorial Air Pollution Program Administrators (STAPPA)

Association of Local Air Pollution Control Officials (ALAPCO)

444 North Capitol Street, N.W. Suite 307 Washington, D.C. 20001

Phone: (202) 624-7864 Fax: (202) 624-7863

Website: www.4cleanair.org